e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)


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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007


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

FOR THE TRANSITION PERIOD FROM TO .

Commission file number 1-13265

CENTERPOINT ENERGY RESOURCES CORP.

(Exact name of registrant as specified in its charter)


Delaware		76-0511406
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1111 Louisiana
Houston, Texas 77002		(713) 207-1111
(Address and zip code of principal executive offices)		(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

As of May 1, 2007, all 1,000 shares of CenterPoint Energy Resources Corp. common stock were held by Utility Holding, LLC, a wholly owned subsidiary of CenterPoint Energy, Inc.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

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

	•		state and federal legislative and regulatory actions or developments, including deregulation, re-regulation, 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;

	•		industrial, commercial and residential growth in our service territory and changes in market demand and demographic patterns;

	•		the timing and extent of changes in commodity prices, particularly natural gas;

	•		changes in interest rates or rates of inflation;

	•		weather variations and other natural phenomena;

	•		the timing and extent of changes in the supply of natural gas;

	•		the timing and extent of changes in natural gas basis differentials;

	•		commercial bank and financial market conditions, our access to capital, the cost of such capital, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets;

	•		actions by rating agencies;

	•		effectiveness of our risk management activities;

	•		inability of various counterparties to meet their obligations to us;

	•		the ability of Reliant Energy, Inc. (RRI) to satisfy its obligations to us or in connection with the contractual arrangements pursuant to which we are a guarantor;

	•		the outcome of litigation brought by or against us;

	•		our ability to control costs;

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

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONDENSED CONSOLIDATED BALANCE SHEETS — (Continued)
(Millions of Dollars)
(Unaudited)

LIABILITIES AND STOCKHOLDER’S EQUITY


	December 31,		March 31,
	2006		2007
Current Liabilities:
Short-term borrowings	$	187	$	337
Current portion of long-term debt		7		307
Accounts payable		928		678
Accounts and notes payable — affiliated companies		386		65
Taxes accrued		115		125
Interest accrued		48		51
Customer deposits		62		57
Non-trading derivative liabilities		141		48
Other		305		256

Total current liabilities		2,179		1,924


Other Liabilities:
Accumulated deferred income taxes, net		662		658
Non-trading derivative liabilities		80		38
Benefit obligations		138		133
Other		669		665

Total other liabilities		1,549		1,494


Long-term Debt		2,155		1,998


Commitments and Contingencies (Note 10)

Stockholder’s Equity:
Common stock		—		—
Paid-in capital		2,403		2,404
Retained earnings		505		636
Accumulated other comprehensive income (loss)		24		(2	)

Total stockholder’s equity		2,932		3,038


Total Liabilities and Stockholder’s Equity	$	8,815	$	8,454

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

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Millions of Dollars)

(Unaudited)


	Three Months Ended March 31,
	2006			2007
Cash Flows from Operating Activities:
Net income	$	97		$	131
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		50			51
Amortization of deferred financing costs		2			2
Deferred income taxes		7			9
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net		438			9
Accounts receivable/payable, affiliates		(2	)		16
Inventory		125			213
Taxes receivable		5			—
Accounts payable		(519	)		(192	)
Fuel cost over recovery		63			23
Interest and taxes accrued		51			13
Non-trading derivatives, net		19			14
Margin deposits, net		(79	)		52
Other current assets		23			34
Other current liabilities		(43	)		(61	)
Other assets		16			(3	)
Other liabilities		(44	)		(28	)
Other, net		12			—

Net cash provided by operating activities		221			283


Cash Flows from Investing Activities:
Capital expenditures		(84	)		(272	)
Increase in notes receivable from affiliates, net		—			(83	)
Other, net		(8	)		(15	)

Net cash used in investing activities		(92	)		(370	)


Cash Flows from Financing Activities:
Proceeds from long-term debt		—			150
Payments of long-term debt		(6	)		(7	)
Increase in short-term borrowings		—			150
Decrease in notes payable with affiliates		(261	)		(186	)
Debt issuance costs		(1	)		(1	)
Contribution from parent		112			—
Other, net		1			1

Net cash provided by (used in) financing activities		(155	)		107


Net Increase (Decrease) in Cash and Cash Equivalents		(26	)		20
Cash and Cash Equivalents at Beginning of the Period		31			5

Cash and Cash Equivalents at End of the Period	$	5		$	25


Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	40		$	41
Income taxes (refunds), net		(110	)		38

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

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1) Background and Basis of Presentation

General. Included in this Quarterly Report on Form 10-Q (Form 10-Q) of CenterPoint Energy Resources Corp. are the condensed consolidated interim financial statements and notes (Interim Condensed Financial Statements) of CenterPoint Energy Resources Corp. and its subsidiaries (collectively, CERC Corp. or the Company). The Interim Condensed Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the Annual Report on Form 10-K of CERC Corp. for the year ended December 31, 2006 (CERC Corp. Form 10-K).

Background. The Company owns and operates natural gas distribution systems in six states. Wholly owned subsidiaries of the Company own interstate natural gas pipelines and gas gathering systems and provide various ancillary services. Another wholly owned subsidiary of the Company offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities.

The Company is an indirect wholly owned subsidiary of CenterPoint Energy, Inc. (CenterPoint Energy), a public utility holding company.

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

The Company’s Interim Condensed Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position, results of operations and cash flows for the respective periods. Amounts reported in the Company’s Condensed Statements of Consolidated Income are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures and (d) acquisitions and dispositions of businesses, assets and other interests. In addition, business segment information for the three months ended March 31, 2006 has been recast to conform to the 2007 presentation due to the change in reportable business segments in the fourth quarter of 2006. The business segment detail revised as a result of the new reportable business segments did not affect consolidated operating income for any period presented.

(2) New Accounting Pronouncements

In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” (FIN 48). FIN 48 clarifies the accounting for uncertain income tax positions and requires the Company to recognize management’s best estimate of the impact of a tax position if it is considered “more likely than not”, as defined in Statement of Financial Accounting Standards (SFAS) No. 5, “Accounting for Contingencies”, of being sustained on audit based solely on the technical merits of the position. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The cumulative effect of adopting FIN 48 as of January 1, 2007 was a credit to retained earnings of less than $1 million. The Company recognizes interest and penalties as a component of income taxes.

The implementation of FIN 48 also impacted other balance sheet accounts. The balance sheet as of January 1, 2007, upon adoption, would have reflected approximately $0.7 million of net unrecognized tax benefits in “Other Liabilities.” This amount includes $0.6 million reclassified from accumulated deferred income taxes to the liability for uncertain tax positions and $9.0 million representing amounts previously accrued for uncertain tax positions that, if recognized, would reduce the effective income tax rate. These liabilities were partially offset by a refund claim of $8.9 million. In addition to these amounts, the Company, at January 1, 2007, accrued approximately $1.3 million for the payment of interest for these uncertain tax positions. The amount of unrecognized tax benefits was not materially different as of March 31, 2007.

CenterPoint Energy’s consolidated federal income tax returns and major state tax returns have been settled through the 1996 tax year.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS No. 157). SFAS No. 157 establishes a framework for measuring fair value and requires expanded disclosure about the information used to measure fair value. The statement applies whenever other statements require or permit assets or liabilities to be measured at fair value. The statement does not expand the use of fair value accounting in any new circumstances and is effective for the Company for the year ended December 31, 2008 and for interim periods included in that year, with early adoption encouraged. The Company is currently evaluating the effect of adoption of this new standard on its financial position, results of operations and cash flows.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 permits the Company to choose, at specified election dates, to measure eligible items at fair value (the “fair value option”). The Company would report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting period. This accounting standard is effective as of the beginning of the first fiscal year that begins after November 15, 2007. The Company is currently evaluating the effect of adoption of this new standard on its financial position, results of operations and cash flows.

(3) Employee Benefit Plans

The Company’s employees participate in CenterPoint Energy’s postretirement benefit plan. The Company’s net periodic cost includes the following components relating to postretirement benefits:


	Three Months Ended
	March 31,
	2006		2007
	(in millions)
Interest cost Service cost	$	2	$	2
Other		1		—

Net periodic cost	$	3	$	2

The Company expects to contribute approximately $19 million to its postretirement benefits plan in 2007, of which $4 million had been contributed as of March 31, 2007.

(4) Regulatory Matters

(a) Rate Cases

Arkansas. In January 2007, the Company’s natural gas distribution business (Gas Operations) filed an application with the Arkansas Public Service Commission (APSC) to change its natural gas distribution rates. This filing seeks approval to change the base rate portion of a customer’s natural gas bill, which makes up about 30 percent of the total bill and covers the cost of distributing natural gas. The filing does not apply to the Gas Supply Rate (GSR), which makes up the remaining approximately 70 percent of the bill. Through the GSR, Gas Operations passes through to its customers the actual cost it pays for the natural gas it purchases for use by its customers without any mark-up. In a separate filing in January 2007, Gas Operations reduced the GSR by approximately 9 percent. The APSC approved this GSR filing in January 2007.

The filing seeks approval by the APSC of new base rates that would go into effect later this year and would generate approximately $51 million in additional revenue on an annual basis. The effect on individual monthly bills would vary depending on natural gas use and customer class. As part of the base rate filing, Gas Operations is also proposing a mechanism that, if approved, would help stabilize revenues, eliminate the potential conflict between its efforts to earn a reasonable return on invested capital while promoting energy efficiency initiatives, and minimize the need for future rate cases. As part of the revenue stabilization mechanism, Gas Operations proposed to reduce the requested return on equity by 35 basis points which would reduce the base rate increase by $1 million. The mechanism would be in place through December 31, 2010.

Texas. In September 2006, Gas Operations filed Statements of Intent (SOI) with 47 cities in its Texas coast service territory to increase miscellaneous service charges and to allow recovery of the costs of financial hedging transactions through its purchased gas cost adjustment. In November 2006, these changes became effective as all 47 cities either approved the filings or took no action, thereby allowing rates to go into effect by operation of law. In December 2006, Gas Operations filed a SOI with the Railroad Commission of Texas (Railroad Commission) seeking to implement such changes in the environs of the Texas coast service territory. The Railroad Commission approved the filing on April 24, 2007. The new service charges are expected to be implemented in the second quarter of 2007.

Minnesota. At September 30, 2006, Gas Operations had recorded approximately $45 million as a regulatory asset related to prior years’ unrecovered purchased gas costs in its Minnesota service territory. Of the total, approximately $24 million related to the period from July 1, 2004 through June 30, 2006, and approximately $21 million related to the period from July 1, 2000 through June 30, 2004. The amounts related to periods prior to July 1, 2004 arose as a result of revisions to the calculation of unrecovered purchased gas costs previously approved by the Minnesota Public Utilities Commission (MPUC). Recovery of this regulatory asset was dependent upon obtaining a waiver from the MPUC rules. In November 2006, the MPUC considered the request for variance and voted to deny the waiver. Accordingly, the Company recorded a $21 million adjustment to reduce pre-tax earnings in the fourth quarter of 2006 and reduced the regulatory asset by an equal amount. In February 2007, the MPUC denied reconsideration. In March 2007, the Company petitioned the Minnesota Court of Appeals for review of the MPUC’s decision. No prediction can be made as to the ultimate outcome of this matter.

In November 2005, Gas Operations filed a request with the MPUC to increase annual rates by approximately $41 million. In December 2005, the MPUC approved an interim rate increase of approximately $35 million that was implemented January 1, 2006. Any excess of amounts collected under the interim rates over the amounts approved in final rates is subject to refund to customers. In October 2006, the MPUC considered the request and indicated that it would grant a rate increase of approximately $21 million. In addition, the MPUC approved a $5 million affordability program to assist low-income customers, the actual cost of which will be recovered in rates in addition to the $21 million rate increase. A final order was issued in January 2007, and final rates were implemented beginning May 1, 2007. The proportional share of the excess of the amounts collected in interim rates over the amount allowed by the final order will be refunded to customers beginning in May 2007. As of December 31, 2006 and March 31, 2007, approximately $12 million and $18 million, respectively, had been accrued for the refund and recorded as a reduction of revenues through the establishment of a regulatory liability.

(b) APSC Affiliate Transaction Rulemaking Proceeding

In December 2006, the APSC adopted new rules governing affiliate transactions involving public utilities operating in Arkansas. In February 2007, in response to requests by the Company and other gas and electric utilities operating in Arkansas, the APSC granted reconsideration of the rules and stayed their operation in order to permit additional consideration. The parties are awaiting the decision of the APSC following that reconsideration. As originally adopted, the rules could have adverse impacts on the Company’s ability to operate and provide cost-effective utility service in Arkansas. Among other things, the rules would treat as affiliate transactions all transactions between the Company’s Arkansas utility operations and other divisions of the Company, as well as transactions between the Arkansas utility operations and affiliates of the Company. All such affiliate transactions would have to be priced under an asymmetrical pricing formula under which the Arkansas utility operations would benefit from any difference between the cost of providing goods and services to or from the Arkansas utility operations and the market value of those goods or services. Additionally, the Arkansas utility operations would not be permitted to participate in any financing other than to finance retail utility operations in Arkansas, which would preclude continuation of existing financing arrangements in which the Company finances its divisions and subsidiaries, including its Arkansas utility operations.

If the rules are not satisfactorily modified as a result of the reconsideration, the Company would be entitled to seek judicial review. If the rules ultimately become effective as originally adopted, the Company anticipates that it would need to seek waivers from certain provisions of the rules or would be required to make significant modifications to existing practices, which could include the formation of and transfer of assets to subsidiaries.

(5) Derivative Instruments

The Company is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Company utilizes derivative instruments such as physical forward contracts, swaps and options (energy derivatives) to mitigate the impact of changes in its natural gas businesses on its operating results and cash flows.

Non-Trading Activities

Cash Flow Hedges. The Company enters into certain derivative instruments that qualify as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). The objective of these derivative instruments is to hedge the price risk associated with natural gas purchases and sales to reduce cash flow variability related to meeting its wholesale and retail customer obligations. During the three months ended March 31, 2006 and 2007, hedge ineffectiveness resulted in a gain of $1 million and a loss of less than $1 million, respectively, from derivatives that qualify for and are designated as cash flow hedges. No component of the derivative instruments’ gain or loss was excluded from the assessment of effectiveness. If it becomes probable that an anticipated transaction being hedged will not occur, the Company realizes in net income the deferred gains and losses previously recognized in accumulated other comprehensive loss. When an anticipated transaction being hedged affects earnings, the accumulated deferred gain or loss recognized in accumulated other comprehensive loss is reclassified and included in the Condensed Statements of Consolidated Income under the “Expenses” caption “Natural gas.” Cash flows resulting from these transactions in non-trading energy derivatives are included in the Condensed Statements of Consolidated Cash Flows in the same category as the item being hedged. As of March 31, 2007, the Company expects $2 million ($1 million after-tax) in accumulated other comprehensive income to be reclassified as an increase in natural gas expense during the next twelve months.

The length of time the Company is hedging its exposure to the variability in future cash flows using financial instruments is primarily two years, with a limited amount up to four years. The Company’s policy is not to exceed ten years in hedging its exposure.

Other Derivative Instruments. The Company enters into certain derivative instruments to manage physical commodity price risks that do not qualify or are not designated as cash flow or fair value hedges under SFAS No. 133. The Company utilizes these financial instruments to manage physical commodity price risks and does not engage in proprietary or speculative commodity trading. During the three months ended March 31, 2006 and 2007, the Company recognized unrealized net gains of $5 million and net losses of $8 million, respectively. These derivative gains and losses are included in the Condensed Statements of Consolidated Income under the “Expenses” caption “Natural gas.”

(6) Goodwill

Goodwill by reportable business segment as of both December 31, 2006 and March 31, 2007 is as follows (in millions):


Natural Gas Distribution	$	746
Interstate Pipelines		579
Competitive Natural Gas Sales and Services		339
Field Services		25
Other Operations		20

Total	$	1,709

(7) Comprehensive Income

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


	For the Three Months Ended
	March 31,
	2006			2007
	(in millions)
Net income	$	97		$	131

Other comprehensive income (loss):
Adjustment to pension and other postretirement benefit plans		—			1
Net deferred loss from cash flow hedges		(3	)		—
Reclassification of deferred gain from cash flow hedges realized in net income		(9	)		(27	)

Other comprehensive loss		(12	)		(26	)

Comprehensive income	$	85		$	105

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


	December 31,			March 31,
	2006			2007
	(in millions)
SFAS No. 158 incremental effect	$	(2	)	$	(1	)
Net deferred gain from cash flow hedges		26			(1	)

Total accumulated other comprehensive income (loss)	$	24		$	(2	)

(8) Related Party Transactions

The Company participates in a “money pool” through which it can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. As of December 31, 2006, the Company had borrowings from the money pool of $186 million. As of March 31, 2007, the Company had investments in the money pool of $80 million.

For each of the three months ended March 31, 2006 and 2007, the Company had net interest expense related to affiliate borrowings of approximately $1 million.

CenterPoint Energy provides some corporate services to the Company. The costs of services have been charged directly to the Company using methods that management believes are reasonable. These methods include negotiated usage rates, dedicated asset assignment and proportionate corporate formulas based on operating expenses, assets, gross margin, employees and a composite of assets, gross margin and employees. These charges are not necessarily indicative of what would have been incurred had the Company not been an affiliate. Amounts charged to the Company for these services were $33 million and $40 million for the three months ended March 31, 2006 and 2007, respectively, and are included primarily in operation and maintenance expenses.

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

(a) Short-term Borrowings

In 2006, the Company amended its receivables facility and extended the termination date to October 30, 2007. The facility size is $375 million until May 2007 and will range from $150 million to $325 million during the period from May 2007 to the October 30, 2007 termination date. Under the terms of the amended receivables facility, the provisions for sale accounting under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” were no longer met. Accordingly, advances received by the Company upon the sale of receivables are accounted for as short-term borrowings as of December 31, 2006 and March 31, 2007. As of December 31, 2006 and March 31, 2007, $187 million and $337 million, respectively, was advanced for the purchase of receivables under the Company’s receivables facility.

(b) Long-term Debt

Senior Notes. In February 2007, the Company issued $150 million aggregate principal amount of senior notes due in February 2037 with an interest rate of 6.25%. The proceeds from the sale of the senior notes were used to repay advances for the purchase of receivables under the Company’s $375 million receivables facility. Such repayment provides increased liquidity and capital resources for general corporate purposes.

Revolving Credit Facility. As of March 31, 2007, the Company had no borrowings and approximately $19 million of outstanding letters of credit under its $550 million credit facility. Additionally, the Company was in compliance with all covenants as of March 31, 2007.

(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, 2006 and March 31, 2007 as these contracts meet the SFAS No. 133 exception to be classified as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas supply commitments also include natural gas transportation contracts which do not meet the definition of a derivative. As of March 31, 2007, minimum payment obligations for natural gas supply commitments are approximately $698 million for the remaining nine months in 2007, $449 million in 2008, $249 million in 2009, $246 million in 2010, $244 million in 2011 and $1.3 billion in 2012 and thereafter.

(b) Legal, Environmental and Other Regulatory Matters

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. On October 20, 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, but the plaintiff has sought review of that dismissal from the Court of Appeals for the 10th Circuit.

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 class of royalty owners, in which they assert their claims that the defendants have engaged in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. The Company believes that there has been no systematic mismeasurement of gas and that the lawsuits are without merit. The Company does not expect the ultimate outcome of the lawsuits to have a material impact on its financial condition, results of operations or cash flows.

Gas Cost Recovery Litigation. In October 2002, a suit was filed in state district court in Wharton County, Texas against the Company, CenterPoint Energy, Entex Gas Marketing Company, and certain non-affiliated companies alleging fraud, violations of the Texas Deceptive Trade Practices Act, violations of the Texas Utilities Code, civil conspiracy and violations of the Texas Free Enterprise and Antitrust Act with respect to rates charged to certain consumers of natural gas in the State of Texas. Subsequently, the plaintiffs added as defendants CenterPoint Energy Marketing Inc., CEGT, United Gas, Inc., Louisiana Unit Gas Transmission Company, CenterPoint Energy Pipeline Services, Inc., and CenterPoint Energy Trading and Transportation Group, Inc., all of which are subsidiaries of the Company. The plaintiffs alleged that defendants inflated the prices charged to certain consumers of natural gas. In February 2003, a similar lawsuit was filed in state court in Caddo Parish, Louisiana against the Company with respect to rates charged to a purported class of certain consumers of natural gas and gas service in the State of Louisiana. In February 2004, another suit was filed in state court in Calcasieu Parish, Louisiana against the Company seeking to recover alleged overcharges for gas or gas services allegedly provided by the Company to a purported class of certain consumers of natural gas and gas service without advance approval by the Louisiana Public Service Commission (LPSC). In October 2004, a similar case was filed in district court in Miller County, Arkansas against the Company, CenterPoint Energy, Entex Gas Marketing Company, CEGT, CenterPoint Energy Field Services, CenterPoint Energy Pipeline Services, Inc., 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 at least the states of Arkansas, Louisiana, Mississippi, Oklahoma and Texas. Subsequently, the plaintiffs dropped as defendants CEGT and MRT. 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 cases have been stayed pending the resolution of the respective proceedings by the LPSC. The plaintiffs in the Miller County case seek class certification, but the proposed class has not been certified. In February 2005, the Wharton County case was removed to federal district court in Houston, Texas, and in March 2005, the plaintiffs voluntarily moved to dismiss the case and agreed not to refile the claims asserted unless the Miller County case is not certified as a class action or is later decertified. The range of relief sought by the plaintiffs in these cases includes injunctive and declaratory relief, restitution for the alleged overcharges, disgorgement of illegal profits, exemplary damages or trebling of actual damages, civil penalties and attorney’s fees. In these cases, the Company, CenterPoint Energy and their affiliates deny that they have overcharged any of their customers for natural gas and believe that the amounts recovered for purchased gas have been in accordance with what is permitted by state and municipal regulatory authorities. The Company does not expect the outcome of these matters to have a material impact on its financial condition, results of operations or cash flows.

Storage Facility Litigation. In February 2007, an Oklahoma district court in Coal County, Oklahoma, granted a summary judgment against CEGT in a case, Deka Exploration, Inc. v. CenterPoint Energy, filed by holders of oil and gas leaseholds and some mineral interest owners in lands underlying CEGT’s Chiles Dome Storage Facility. The dispute concerns “native gas” that may have been in the Wapanucka formation underlying the Chiles Dome facility when that facility was constructed in 1979 by a CERC entity that was the predecessor in interest of CEGT. The court ruled that the plaintiffs own native gas underlying those lands, since neither CEGT nor its predecessors had condemned those ownership interests. The court rejected CEGT’s contention that the claim should be barred by the statute of limitations, since 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 which imposes liability on CEGT in this matter. The Company does not expect the outcome of this matter to have a material impact on its financial condition, results of operations or cash flows.

Environmental Matters

Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are among the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and Bossier Parish, Louisiana. The suits allege that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination is alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the “Sligo Facility,” which was formerly

operated by a predecessor in interest of CERC Corp. This facility was purportedly used for gathering natural gas from surrounding wells, separating liquid hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution.

Beginning about 1985, the predecessors of certain CERC Corp. defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they owned or leased. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. The plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, including the cost of restoring their property to its original condition and damages for diminution of value of their property. In addition, plaintiffs seek damages for trespass, punitive, and exemplary damages. The parties have reached an agreement on terms of a settlement in principle of this matter. That settlement would require approval from the Louisiana Department of Environmental Quality of an acceptable remediation plan that could be implemented by the Company. The Company currently is seeking that approval. If the currently agreed terms for settlement are ultimately implemented, the Company does not expect the ultimate cost associated with resolving this matter to have a material impact on its financial condition, results of operations or cash flows.

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

At March 31, 2007, the Company had accrued $14 million for remediation of these Minnesota sites and the estimated range of possible remediation costs for these sites was $4 million to $35 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. The Company has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. As of March 31, 2007, the Company had collected $13 million from insurance companies and rate payers to be used for future environmental remediation.

In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by the Company or may have been owned by one of its former affiliates. The Company has been named as a defendant in a lawsuit filed in the United States District Court, District of Maine, under which contribution is sought by private parties for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of the Company or its divisions. The Company has also been identified as a PRP by the State of Maine for a site that is the subject of the lawsuit. In June 2006, the federal district court in Maine ruled that the current owner of the site is responsible for site remediation but that an additional evidentiary hearing is required to determine if other potentially responsible parties, including the Company, would have to contribute to that remediation. The Company is investigating details regarding the site and the range of environmental expenditures for potential remediation. However, the Company believes it is not liable as a former owner or operator of the site under the Comprehensive Environmental, Response, Compensation and Liability Act of 1980, as amended, and applicable state statutes, and is vigorously contesting those suits and its designation as a PRP.

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

Asbestos. Some facilities formerly owned by the Company’s predecessors have contained asbestos insulation and other asbestos-containing materials. The Company or its predecessor companies have been named, along with

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

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

Other Proceedings

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

Guaranties

Prior to CenterPoint Energy’s distribution of its ownership in Reliant Energy, Inc. (RRI) to its shareholders, the Company had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guaranty obligations prior to separation, but at the time of separation in September 2002, RRI had been unable to extinguish all obligations. To secure the Company and CenterPoint Energy against obligations under the remaining guaranties, RRI agreed to provide cash or letters of credit for the benefit of the Company and CenterPoint Energy, and undertook to use commercially reasonable efforts to extinguish the remaining guaranties. The Company currently holds letters of credit in the amount of $33.3 million issued on behalf of RRI against guaranties that have not been released. CenterPoint Energy’s current exposure under the guaranties relates to the Company’s guaranty of the payment by RRI of demand charges related to transportation contracts with one counterparty. The demand charges are approximately $53 million per year through 2015, $49 million in 2016, $38 million in 2017 and $13 million in 2018. RRI continues to meet its obligations under the transportation contracts, and the Company believes current market conditions make those contracts valuable for transportation services in the near term. However, changes in market conditions could affect the value of those contracts. If RRI should fail to perform its obligations under the transportation contracts, the Company’s exposure to the counterparty under the guaranty could exceed the security provided by RRI. CenterPoint Energy has requested RRI to increase the amount of its existing letters of credit or, in the alternative, to obtain a release of the Company’s obligations under the guaranty. In June 2006, the RRI trading subsidiary and the Company jointly filed a complaint at the FERC against the counterparty on the Company’s guaranty. In the complaint, the RRI trading subsidiary seeks a determination by the FERC that the security demanded by the counterparty exceeds the level permitted by the FERC’s policies. The complaint asks the FERC to require the counterparty to release the Company from its guaranty obligation and, in its place, accept (i) a guaranty from RRI of the obligations of the RRI trading subsidiary, and (ii) letters of credit limited to (A) one year of demand charges for a transportation agreement related to a 2003 expansion of the counterparty’s pipeline, and (B) three months of demand charges for three other transportation agreements held by the RRI trading subsidiary. The counterparty has argued that the amount of the guaranty does not violate the FERC’s policies and that the proposed substitution of credit support is not authorized under the counterparty’s financing documents or required by the FERC’s policy. The parties have now completed their submissions to the FERC regarding the complaint. The Company cannot predict what action the FERC may take on the complaint or when the FERC may rule. In addition to the FERC proceeding, in February 2007 the Company and CenterPoint Energy made a formal demand on RRI under procedures provided by the Master Separation Agreement, dated as of December 31, 2000, between Reliant Energy and RRI. That demand seeks to resolve the disagreement with RRI over the amount of security RRI is obligated to provide with respect to this guaranty. In conjunction with discussion of that demand, CenterPoint

Energy and RRI entered into an agreement in March 2007 to delay further proceedings regarding this dispute until October 2007 in order to permit further discussions. It is possible that an arbitration proceeding between the companies could be pursued, but when and on what terms the disagreement with RRI will ultimately be resolved cannot be predicted.

(11) Reportable Business Segments

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

The Company’s reportable business segments include the following: Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines, Field Services and Other Operations. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers. Competitive Natural Gas Sales and Services represents the Company’s non-rate regulated gas sales and services operations, which consist of three operational functions: wholesale, retail and intrastate pipelines. Beginning in the fourth quarter of 2006, the Company began reporting its interstate pipelines and field services businesses as two separate business segments, the Interstate Pipelines business segment and the Field Services business segment. These business segments were previously aggregated and reported as the Pipelines and Field Services business segment. 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. All prior periods have been recast to conform to the 2007 presentation.

Long-lived assets include net property, plant and equipment, net goodwill 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, 2006
	Revenues from		Net						Total Assets
	External		Intersegment			Operating			as of December 31,
	Customers		Revenues			Income (Loss)			2006
Natural Gas Distribution	$	1,477	$	3		$	103		$	4,463
Competitive Natural Gas Sales and Services		1,126		37			25			1,501
Interstate Pipelines		56		33			49			2,738
Field Services		31		10			24			608
Other Operations		—		2			(1	)		1,086
Eliminations		—		(85	)		—			(1,581	)

Consolidated	$	2,690	$	—		$	200		$	8,815


	For the Three Months Ended March 31, 2007
	Revenues from			Net						Total Assets
	External			Intersegment			Operating Income			as of March 31,
	Customers			Revenues			(Loss)			2007
Natural Gas Distribution	$	1,564		$	3		$	129		$	4,226
Competitive Natural Gas Sales and Services		1,047			17			56			1,312
Interstate Pipelines		59			31			44			2,688
Field Services		28			11			22			597
Other Operations		(1	)		—			(1	)		609
Eliminations		—			(62	)		—			(978	)

Consolidated	$	2,697		$	—		$	250		$	8,454

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

The following narrative analysis should be read in combination with our Interim Condensed Financial Statements contained in Item 1 of this report.

We meet the conditions specified in General Instruction H(1)(a) and (b) to Form 10-Q and are therefore permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies. Accordingly, we have omitted from this report the information called for by Item 2 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Item 3 (Quantitative and Qualitative Disclosures About Market Risk) of Part I and the following Part II items of Form 10-Q: Item 2 (Unregistered Sales of Equity Securities and Use of Proceeds), Item 3 (Defaults Upon Senior Securities) and Item 4 (Submission of Matters to a Vote of Security Holders). The following discussion explains material changes in our revenue and expense items between the three months ended March 31, 2006 and the three months ended March 31, 2007. Reference is made to “Management’s Narrative Analysis of the Results of Operations” in Item 7 of the Annual Report on Form 10-K of CERC Corp. for the year ended December 31, 2006 (CERC Corp. Form 10-K).

EXECUTIVE SUMMARY

Recent Events

Debt Financing Transactions

In February 2007, we issued $150 million aggregate principal amount of senior notes due in February 2037 with an interest rate of 6.25%. The proceeds from the sale of the senior notes were used to repay advances for the purchase of receivables under our $375 million receivables facility. Such repayment provides increased liquidity and capital resources for general corporate purposes.

Interstate Pipeline Expansion

Carthage to Perryville. In April 2007, CenterPoint Energy Gas Transmission (CEGT), our wholly owned subsidiary, completed construction of 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. On May 1, 2007, CEGT began service under its firm transportation agreements with shippers of approximately 960 million cubic feet per day. This completes the first phase of the Carthage to Perryville project. The second phase of the project remains on schedule for a mid-summer completion and involves adding compression to increase the total capacity of the pipeline to approximately 1.25 billion cubic feet (Bcf) per day. CEGT has signed firm contracts for the full capacity of the 1.25 Bcf per day pipeline.

CONSOLIDATED RESULTS OF OPERATIONS

Our results of operations are affected by seasonal fluctuations in the demand for natural gas and price movements of energy commodities. Our results of operations are also affected by, among other things, the actions of various federal, state and local governmental authorities having jurisdiction over rates we charge, competition in our various business operations, debt service costs and income tax expense. For more information regarding factors that may affect the future results of operations of our business, please read “Risk Factors” in Item 1A of Part I of the CERC Corp. Form 10-K.

The following table sets forth our consolidated results of operations for the three months ended March 31, 2006 and 2007, followed by a discussion of the results of operations by business segment based on operating income.


	Three Months Ended March 31,
	2006			2007
	(in millions)
Revenues	$	2,690		$	2,697

Expenses:
Natural gas		2,193			2,150
Operation and maintenance		197			198
Depreciation and amortization		50			51
Taxes other than income taxes		50			48

Total Expenses		2,490			2,447

Operating Income		200			250
Interest and Other Finance Charges		(40	)		(39	)
Other Income, net		3			3

Income Before Income Taxes		163			214
Income Tax Expense		(66	)		(83	)

Net Income	$	97		$	131

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, 2006 and 2007. Due to the change in reportable segments in the fourth quarter of 2006, we have recast our segment information for 2006, as discussed in Note 11 to our Interim Condensed Financial Statements, to conform to the new presentation. The segment detail revised as a result of the new reportable business segments did not affect consolidated operating income for any period.


	Three Months Ended March 31,
	2006			2007
Natural Gas Distribution	$	103		$	129
Competitive Natural Gas Sales and Services		25			56
Interstate Pipelines		49			44
Field Services		24			22
Other Operations		(1	)		(1	)

Total Consolidated Operating Income	$	200		$	250

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 the CERC Corp. Form 10-K.

The following table provides summary data of our Natural Gas Distribution business segment for the three months ended March 31, 2006 and 2007 (in millions, except throughput and customer data):


	Three Months Ended March 31,
	2006		2007
Revenues	$	1,480	$	1,567

Expenses:
Natural gas		1,146		1,212
Operation and maintenance		150		147
Depreciation and amortization		38		38
Taxes other than income taxes		43		41

Total expenses		1,377		1,438

Operating Income	$	103	$	129


Throughput (in Bcf):
Residential		67		86
Commercial and industrial		72		81

Total Throughput		139		167


Average number of customers:
Residential		2,896,766		2,946,203
Commercial and industrial		245,766		245,576

Total		3,142,532		3,191,779

Three months ended March 31, 2007 compared to three months ended March 31, 2006

Our Natural Gas Distribution business segment reported operating income of $129 million for the three months ended March 31, 2007 compared to operating income of $103 million for the three months ended March 31, 2006. Higher operating margins (revenues less natural gas costs) from increased usage due to a return to normal weather ($20 million) and growth from the addition of approximately 48,000 customers since March 31, 2006 ($4 million) were partially offset by lower final base rates in Minnesota compared to interim rates accrued in the first quarter of 2006 ($3 million). Operation and maintenance expenses decreased primarily due to costs associated with staff reductions incurred in 2006 ($6 million) and resulting labor savings in 2007 ($3 million), partially offset by higher costs related to improvements in customer service ($3 million) and higher bad debt expense ($3 million).

Competitive Natural Gas Sales and Services

For information regarding factors that may affect the future results of operations of our Competitive Natural Gas Sales and Services business segment, please read “Risk Factors — Risk Factors Affecting Our 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 the CERC Corp. 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, 2006 and 2007 (in millions, except throughput and customer data):


	Three Months Ended March 31,
	2006		2007
Revenues	$	1,163	$	1,064

Expenses:
Natural gas		1,129		998
Operation and maintenance		8		9
Depreciation and amortization		––		––
Taxes other than income taxes		1		1

Total expenses		1,138		1,008

Operating Income	$	25	$	56


Throughput (in Bcf):
Wholesale – third parties		89		94
Wholesale – affiliates		11		3
Retail and Pipeline		58		58

Total Throughput		158		155


Average number of customers:
Wholesale		145		223
Retail and Pipeline		6,664		6,764

Total		6,809		6,987

Three months ended March 31, 2007 compared to three months ended March 31, 2006

Our Competitive Natural Gas Sales and Services business segment reported operating income of $56 million for the three months ended March 31, 2007 compared to $25 million for the three months ended March 31, 2006. The increase in operating income of $31 million was primarily due to increased operating margins (revenues less natural gas costs) related to sales of gas from inventory ($28 million) partially offset by an unfavorable change resulting from mark-to-market accounting for non-trading financial derivatives ($14 million). The first quarter of 2006 included a $13 million write-down of natural gas inventory to the lower of average cost or market. Natural gas that is purchased for inventory is accounted for at the lower of average cost or market price at each balance sheet date.

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 the CERC Corp. Form 10-K.

The following table provides summary data of our Interstate Pipelines business segment for the three months ended March 31, 2006 and 2007 (in millions, except throughput data):


	Three Months Ended March 31,
	2006			2007
Revenues	$	89		$	90

Expenses:
Natural gas		(2	)		4
Operation and maintenance		27			27
Depreciation and amortization		10			10
Taxes other than income taxes		5			5

Total expenses		40			46

Operating Income	$	49		$	44


Throughput (in Bcf):
Transportation		274			294

Three months ended March 31, 2007 compared to three months ended March 31, 2006

The Interstate Pipeline business segment reported operating income of $44 million for the three months ended March 31, 2007 compared to $49 million for the same period of 2006. The decrease in operating income was primarily due to the absence of a favorable storage adjustment recorded in the first quarter of 2006 ($3 million). Additionally, increased operation and maintenance expenses ($4 million) were offset primarily by the sale of excess gas from our storage enhancement project ($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 the CERC Corp. Form 10-K.

The following table provides summary data of our Field Services business segment for the three months ended March 31, 2006 and 2007 (in millions, except throughput data):


	Three Months Ended March 31,
	2006		2007
Revenues	$	41	$	39

Expenses:
Natural gas		1		(3	)
Operation and maintenance		13		16
Depreciation and amortization		3		3
Taxes other than income taxes		—		1

Total expenses		17		17

Operating Income	$	24	$	22


Throughput (in Bcf ):
Gathering		88		93

Three months ended March 31, 2007 compared to three months ended March 31, 2006

The Field Services business segment reported operating income of $22 million for the three months ended March 31, 2007 compared to $24 million for the same period of 2006. Continued increased demand for gas gathering and ancillary services ($7 million) was more than offset by lower commodity prices ($5 million) and increased operation and maintenance expenses ($3 million) related to cost increases and expanded operations. In addition, this business segment recorded equity income of $2 million in each of the three months ended March 31,

2006 and 2007 from its 50 percent interest in a jointly-owned gas processing plant. These amounts are included in Other – net under the Other Income (Expense) caption.

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

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

LIQUIDITY AND CAPITAL RESOURCES

Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, and working capital needs. Our principal cash requirements for the remaining nine months of 2007 are approximately $460 million of capital expenditures and an investment in the Southeast Supply Header (SESH) pipeline project of approximately $150 million.

We expect that borrowings under our credit facility, anticipated cash flows from operations and borrowings from affiliates will be sufficient to meet our cash needs for the remaining nine months of 2007. Cash needs or discretionary financing or refinancing may also result in the issuance of equity or debt securities in the capital markets.

Arkansas Public Service Commission (APSC) Affiliate Transaction Rulemaking Proceeding. In December 2006, the APSC adopted new rules governing affiliate transactions involving public utilities operating in Arkansas. In February 2007, in response to requests by us and other gas and electric utilities operating in Arkansas, the APSC granted reconsideration of the rules and stayed their operation in order to permit additional consideration. The parties are awaiting the decision of the APSC following that reconsideration. As originally adopted, the rules could have adverse impacts on our ability to operate and provide cost-effective utility service in Arkansas. For example, the rules would treat as affiliate transactions all transactions between our Arkansas utility operations and our other divisions, as well as transactions between the Arkansas utility operations and our affiliates. All such affiliate transactions would have to be priced under an asymmetrical pricing formula under which the Arkansas utility operations would benefit from any difference between the cost of providing goods and services to or from the Arkansas utility operations and the market value of those goods or services. Additionally, the Arkansas utility operations would not be permitted to participate in any financing other than to finance retail utility operations in Arkansas, which would preclude continuation of existing financing arrangements in which we finance our divisions and subsidiaries, including our Arkansas utility operations.

If the rules are not satisfactorily modified as a result of the reconsideration, we would be entitled to seek judicial review. If the rules ultimately become effective as originally adopted, we anticipate that we would need to seek waivers from certain provisions of the rules or would be required to make significant modifications to existing practices, which could include the formation of and transfer of assets to subsidiaries.

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

Prior to CenterPoint Energy’s distribution of its ownership in Reliant Energy, Inc. (RRI) to its shareholders, we had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guaranty obligations prior to separation, but at the time of separation in September 2002, RRI had been unable to extinguish all obligations. To secure CenterPoint Energy and us against obligations under the remaining guaranties, RRI agreed to provide cash or letters of credit for our benefit and that of CenterPoint Energy, and undertook to use commercially reasonable efforts to extinguish the remaining guaranties. We currently hold letters of credit in the amount of $33.3 million issued on behalf of RRI against guaranties that have not been released. Our current exposure under the guaranties relates to our guaranty of the payment by RRI of demand charges related to transportation contracts with one counterparty. The demand charges are approximately $53 million per year through 2015, $49 million in 2016, $38 million in 2017 and $13 million in 2018. RRI continues to meet its obligations under the transportation contracts, and we believe current market conditions make those contracts valuable for transportation services in the near term. However,

changes in market conditions could affect the value of those contracts. If RRI should fail to perform its obligations under the transportation contracts, our exposure to the counterparty under the guaranty could exceed the security provided by RRI. We have requested RRI to increase the amount of its existing letters of credit or, in the alternative, to obtain a release of our obligations under the guaranty. In June 2006, we and the RRI trading subsidiary jointly filed a complaint at the Federal Energy Regulatory Commission (FERC) against the counterparty on our guaranty. In the complaint, the RRI trading subsidiary seeks a determination by the FERC that the security demanded by the counterparty exceeds the level permitted by the FERC’s policies. The complaint asks the FERC to require the counterparty to release us from our guaranty obligation and, in its place, accept (i) a guaranty from RRI of the obligations of the RRI trading subsidiary, and (ii) letters of credit limited to (A) one year of demand charges for a transportation agreement related to a 2003 expansion of the counterparty’s pipeline, and (B) three months of demand charges for three other transportation agreements held by the RRI trading subsidiary. The counterparty has argued that the amount of the guaranty does not violate the FERC’s policies and that the proposed substitution of credit support is not authorized under the counterparty’s financing documents or required by the FERC’s policy. The parties have now completed their submissions to the FERC regarding the complaint. We cannot predict what action the FERC may take on the complaint or when the FERC may rule. In addition to the FERC proceeding, in February 2007 we and CenterPoint Energy made a formal demand on RRI under procedures provided by the Master Separation Agreement, dated as of December 31, 2000, between Reliant Energy, Incorporated and Reliant Resources, Inc. That demand seeks to resolve the disagreement with RRI over the amount of security RRI is obligated to provide with respect to this guaranty. In conjunction with discussion of that demand, CenterPoint Energy and RRI entered into an agreement in March 2007 to delay further proceedings regarding this dispute until October 2007 in order to permit further discussions. It is possible that an arbitration proceeding between the companies could be pursued, but when and on what terms the disagreement with RRI will ultimately be resolved cannot be predicted.

Senior Notes. In February 2007, we issued $150 million aggregate principal amount of senior notes due in February 2037 with an interest rate of 6.25%. The proceeds from the sale of the senior notes were used to repay advances for the purchase of receivables under our $375 million receivables facility. Such repayment provides increased liquidity and capital resources for general corporate purposes.

Credit and Receivables Facilities. As of May 1, 2007, we had the following facilities (in millions):

Amount Utilized at

Date Executed

Company

Type of Facility

Size of Facility

May 1, 2007

Termination Date

March 31, 2006

CERC Corp.

Revolver

550

⁽¹⁾

March 31, 2011

October 31, 2006

CERC

Receivables

375

269

October 30, 2007


(1)		Represents outstanding letters of credit.

Under each of our credit facilities, an additional utilization fee of 10 basis points applies to borrowings any time more than 50% of the facility is utilized, and the spread to London Interbank Offered Rate fluctuates 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 make representations prior to borrowings as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under each of the credit facilities are subject to acceleration upon the occurrence of events of default that we consider customary.

The termination date of our receivables facility is in October 2007. The facility size is $375 million to May 2007 and ranges from $150 million to $325 million during the period from May 2007 to the October 30, 2007 termination date of the facility.

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

Securities Registered with the SEC. At March 31, 2007, we had a shelf registration statement covering $350 million principal amount of debt securities.

Temporary Investments. As of March 31, 2007, we had external temporary investments of approximately $6 million. As of May 1, 2007, we had external temporary investments of $16 million.

Money Pool. We participate in a money pool through which we and certain of our affiliates can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. At May 1, 2007, we had no investments in or borrowings from the money pool. The money pool may not provide sufficient funds to meet our cash needs.

Impact on Liquidity of a Downgrade in Credit Ratings. As of May 1, 2007, Moody’s Investors Service, Inc. (Moody’s), Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies (S&P) and Fitch, Inc. (Fitch) had assigned the following credit ratings to our senior unsecured debt:


Moody’s		S&P		Fitch
Rating	Outlook(1)	Rating	Outlook(2)	Rating	Outlook(3)
Baa3	Stable	BBB	Positive	BBB	Stable


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

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

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

We cannot assure you that these ratings will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing, the cost of such financings, the willingness of suppliers to extend credit lines to us on an unsecured basis and the execution of our commercial strategies.

A decline in credit ratings could increase borrowing costs under our $550 million revolving credit facility. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact our ability to complete capital market transactions. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce margins of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments.

CenterPoint Energy Services, Inc. (CES), a wholly owned subsidiary operating in our Competitive Natural Gas Sales and Services business segment, provides comprehensive natural gas sales and services primarily to commercial and industrial customers and electric and gas utilities throughout the central and eastern United States. In order to economically hedge its exposure to natural gas prices, CES uses derivatives with provisions standard for the industry, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the credit exposure that a counterparty has to CES at a particular time does not exceed that credit threshold, CES is not obligated to provide collateral. Mark-to-market exposure in excess of the credit threshold is routinely collateralized by CES. As of March 31, 2007, the amount posted as collateral amounted to approximately $61 million. Should our credit ratings (the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral on two business days’ notice up to the amount of its previously unsecured credit limit. We estimate that as of March 31, 2007, unsecured credit limits extended to CES by counterparties aggregate $133 million; however, utilized credit capacity is significantly lower. In addition, we and our subsidiaries purchase natural gas under supply agreements that contain an aggregate credit threshold of $100 million based on our S&P Senior Unsecured Long-Term Debt rating of BBB. Upgrades and downgrades from this BBB rating will increase and decrease the aggregate credit threshold accordingly.

In connection with the development of SESH’s 270 mile pipeline project, we have committed that we will advance funds to the joint venture or cause funds to be advanced, up to $400 million, for its 50 percent share of the

cost to construct the pipeline. CERC Corp. also agreed to provide a letter of credit in the amount of its share of funds that have not been advanced in the event S&P reduces our bond rating below investment grade before we have advanced the required construction funds. However, we are relieved of these commitments (i) to the extent of 50 percent of any borrowing agreements that the joint venture has obtained and maintains for funding the construction of the pipeline and (ii) to the extent we or our subsidiary participating in the joint venture obtains committed borrowing agreements pursuant to which funds may be borrowed and used for the construction of the pipeline. A similar commitment has been provided by the other party to the joint venture. As of March 31, 2007, our subsidiary, CenterPoint Energy Southeastern Pipelines Holding, LLC, has funded $25 million to SESH.

Cross Defaults. Under CenterPoint Energy’s revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $50 million by us will cause a default. Pursuant to the indenture governing CenterPoint Energy’s senior notes, a payment default by us, in respect of, or an acceleration of, borrowed money and certain other specified types of obligations, in the aggregate principal amount of $50 million will cause a default. As of May 1, 2007, CenterPoint Energy had six series of senior notes outstanding aggregating $1.4 billion in principal amount under this indenture. A default by CenterPoint Energy would not trigger a default under our debt instruments or bank credit facilities.

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

	•		cash collateral requirements that could exist in connection with certain contracts, including gas purchases, gas price hedging and gas storage activities of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, particularly given gas price levels and volatility;

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

	•		increased costs related to the acquisition of natural gas;

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

	•		various regulatory actions;

	•		the ability of RRI and its subsidiaries to satisfy their obligations to us or in connection with the contractual arrangement pursuant to which we are a guarantor;

	•		slower customer payments and increased write-offs of receivables due to higher gas prices or changing economic conditions;

	•		the outcome of litigation brought by and against us;

	•		contributions to benefit plans;

	•		restoration costs and revenue losses resulting from natural disasters such as hurricanes; and

	•		various other risks identified in “Risk Factors” in Item 1A of the CERC Corp. Form 10-K.

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

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

CRITICAL ACCOUNTING POLICIES

A critical accounting policy is one that is both important to the presentation of our financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in our historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require us to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that we could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of our financial condition or results of operations. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. Our significant accounting policies are discussed in Note 2 to the consolidated financial statements of the CERC Corp. Form 10-K. We believe the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the audit committee of the board of directors of CenterPoint Energy.

Impairment of Long-Lived Assets and Intangibles

We review the carrying value of our long-lived assets, including goodwill and identifiable intangibles, whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and annually for goodwill as required by Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets.” No impairment of goodwill was indicated based on our annual analysis as of July 1, 2006. Unforeseen events and changes in circumstances and market conditions and material differences in the value of long-lived assets and intangibles due to changes in estimates of future cash flows, regulatory matters and operating costs could negatively affect the fair value of our assets and result in an impairment charge.

Fair value is the amount at which the asset could be bought or sold in a current transaction between willing parties and may be estimated using a number of techniques, including quoted market prices or valuations by third parties, present value techniques based on estimates of cash flows, or multiples of earnings or revenue performance measures. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.

Asset Retirement Obligations

We account for our long-lived assets under SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143), and Financial Accounting Standards Board Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations — An Interpretation of SFAS No. 143” (FIN 47). SFAS No. 143 and FIN 47 require that an asset retirement obligation be recorded at fair value in the period in which it is incurred if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. Rate-regulated entities may recognize regulatory assets or liabilities as a result of timing differences between the recognition of costs as recorded in accordance with SFAS No. 143 and FIN 47, and costs recovered through the ratemaking process.

We estimate the fair value of asset retirement obligations by calculating the discounted cash flows that are dependent upon the following components:

	•		Inflation adjustment — The estimated cash flows are adjusted for inflation estimates for labor, equipment, materials, and other disposal costs;

	•		Discount rate — The estimated cash flows include contingency factors that were used as a proxy for the market risk premium; and

	•		Third-party markup adjustments — Internal labor costs included in the cash flow calculation were adjusted

for costs that a third party would incur in performing the tasks necessary to retire the asset.

Changes in these factors could materially affect the obligation recorded to reflect the ultimate cost associated with retiring the assets under SFAS No. 143 and FIN 47. For example, if the inflation adjustment increased 25 basis points, this would increase the balance for asset retirement obligations by approximately 4%. Similarly, an increase in the discount rate by 25 basis points would decrease asset retirement obligations by approximately 3%. At March 31, 2007, our estimated cost of retiring these assets was approximately $67 million.

Unbilled Revenues

Revenues related to the sale and/or delivery of natural gas are generally recorded when natural gas is delivered to customers. However, the determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of natural gas delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Unbilled natural gas sales are estimated based on estimated purchased gas volumes, estimated lost and unaccounted for gas and tariffed rates in effect. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

NEW ACCOUNTING PRONOUNCEMENTS

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

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, 2007 to provide assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.

There has been no change in our internal controls over financial reporting that occurred during the three months ended March 31, 2007 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

Item 5. Other Information

Our ratio of earnings to fixed charges for the three months ended March 31, 2006 and 2007 was 4.69 and 5.19, respectively. We do not believe that the ratios for these three-month periods are necessarily indicators of the ratios

for the twelve-month periods due to the seasonal nature of our business. The ratios were calculated pursuant to applicable rules of the Securities and Exchange Commission.

Item 6. Exhibits

The following exhibits are filed herewith:

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

Report or

SEC File or

Exhibit

Registration

Exhibit

Number

Description

Statement

Number

Reference

3.1.1

–

Certificate of Incorporation of RERC Corp.

Form 10-K for the year ended December 31, 1997

1-13265

3(a

)(1)

3.1.2

–

Certificate of Merger merging former NorAm Energy Corp. with and into HI Merger, Inc. dated August 6, 1997

Form 10-K for the year ended December 31, 1997

1-13265

3(a

)(2)

3.1.3

–

Certificate of Amendment changing the name to Reliant Energy Resources Corp.

Form 10-K for the year ended December 31, 1998

1-13265

3(a

)(3)

3.1.4

–

Certificate of Amendment changing the name to CenterPoint Energy Resources Corp.

Form 10-Q for the quarter ended June 30, 2003

1-13265

3(a

)(4)

3.2

–

Bylaws of RERC Corp.

Form 10-K for the year ended December 31, 1997

1-13265

(b)

4.1

–

$550,000,000 Credit Agreement dated as of March 31, 2006, among CERC Corp., as Borrower, and the banks named therein

CERC Corp.’s Form 8-K dated March 31, 2006

1-13265

4.3

4.2

–

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

CERC Corp.’s Form 8-K dated February 5, 1998

1-13265

4.1

4.3

–

Supplemental Indenture No. 10 to Exhibit 4.6, dated as of February 6, 2007, providing for the issuance of CERC Corp.’s 6.25% Senior Notes due 2037

CenterPoint Energy’s Form 10-K for the year ended December 31, 2006

1-31447

4(f

)(11)

+12

–

Computation of Ratios of Earnings to Fixed Charges

+31.1

–

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

+31.2

–

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

+32.1

–

Section 1350 Certification of David M. McClanahan

+32.2

–

Section 1350 Certification of Gary L. Whitlock

+99.1

–

Items incorporated by reference from the CERC Corp. Form 10-K. Item 1A “—Risk Factors.”

EXHIBIT INDEX

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.

Report or

SEC File or

Exhibit

Registration

Exhibit

Number

Description

Statement

Number

Reference

3.1.1

–

Certificate of Incorporation of RERC Corp.

Form 10-K for the year ended December 31, 1997

1-13265

3(a

)(1)

3.1.2

–

Certificate of Merger merging former NorAm Energy Corp. with and into HI Merger, Inc. dated August 6, 1997

Form 10-K for the year ended December 31, 1997

1-13265

3(a

)(2)

3.1.3

–

Certificate of Amendment changing the name to Reliant Energy Resources Corp.

Form 10-K for the year ended December 31, 1998

1-13265

3(a

)(3)

3.1.4

–

Certificate of Amendment changing the name to CenterPoint Energy Resources Corp.

Form 10-Q for the quarter ended June 30, 2003

1-13265

3(a

)(4)

3.2

–

Bylaws of RERC Corp.

Form 10-K for the year ended December 31, 1997

1-13265

(b)

4.1

–

$550,000,000 Credit Agreement dated as of March 31, 2006, among CERC Corp., as Borrower, and the banks named therein

CERC Corp.’s Form 8-K dated March 31, 2006

1-13265

4.3

4.2

–

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

CERC Corp.’s Form 8-K dated February 5, 1998

1-13265

4.1

4.3

–

Supplemental Indenture No. 10 to Exhibit 4.6, dated as of February 6, 2007, providing for the issuance of CERC Corp.’s 6.25% Senior Notes due 2037

CenterPoint Energy’s Form 10-K for the year ended December 31, 2006

1-31447

4(f

)(11)

+12

–

Computation of Ratios of Earnings to Fixed Charges

+31.1

–

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

+31.2

–

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

+32.1

–

Section 1350 Certification of David M. McClanahan

+32.2

–

Section 1350 Certification of Gary L. Whitlock

+99.1

–

Items incorporated by reference from the CERC Corp. Form 10-K. Item 1A “—Risk Factors.”


	December 31,			March 31,
	2006			2007
Current Assets:
Cash and cash equivalents	$	5		$	25
Accounts and notes receivable, net		846			947
Accrued unbilled revenue		356			246
Accounts and notes receivable – affiliated companies		198			130
Materials and supplies		31			32
Natural gas inventory		305			91
Non-trading derivative assets		98			44
Deferred tax asset		2			1
Prepaid expenses and other current assets		360			193

Total current assets		2,201			1,709


Property, Plant and Equipment:
Property, plant and equipment		5,336			5,538
Less accumulated depreciation and amortization		(697	)		(725	)

Property, plant and equipment, net		4,639			4,813


Other Assets:
Goodwill		1,709			1,709
Non-trading derivative assets		21			16
Other		245			207

Total other assets		1,975			1,932


Total Assets	$	8,815		$	8,454


	CENTERPOINT ENERGY RESOURCES CORP.

	By:	/s/ James S. Brian
		James S. Brian
	Senior Vice President and Chief Accounting Officer

Date: May 9, 2007

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements			1
Condensed Statements of Consolidated Income Three Months Ended March 31, 2006 and 2007 (unaudited)			1
Condensed Consolidated Balance Sheets December 31, 2006 and March 31, 2007 (unaudited)			2
Condensed Statements of Consolidated Cash Flows Three Months Ended March 31, 2006 and 2007 (unaudited)			4
Notes to Unaudited Condensed Consolidated Financial Statements			5
Item 2. Management’s Narrative Analysis of the Results of Operations			15
Item 4. Controls and Procedures			25

PART II. OTHER INFORMATION
Item 1. Legal Proceedings			25
Item 1A. Risk Factors			25
Item 5. Other Information			25
Item 6. Exhibits			26
Computation of Ratio of Earnings to Fixed Charges
Rule 13a-14(a)/15d-14(a) Certification
Rule 13a-14(a)/15d-14(a) Certification
Section 1350 Certification
Section 1350 Certification
Items Incorporated by reference from the Form 10-K

	•		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; and

	•		other factors we discuss in “Risk Factors” in Item 1A of Part I of our Annual Report on Form 10-K for the year ended December 31, 2006, which is incorporated herein by reference, and other reports we file from time to time with the Securities and Exchange Commission.