CENTERPOINT ENERGY RESOURCES CORP - FORM 10-Q

Attached files

file	filename
EX-12 - COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES - CENTERPOINT ENERGY RESOURCES CORP	ex12.htm
EX-32.1 - SECTION 1350 CERTIFICATION OF DAVID M. MCCLANAHAN - CENTERPOINT ENERGY RESOURCES CORP	ex32-1.htm
EX-31.2 - RULE 13A-14(A)/15D-14(A) CERTIFICATION OF GARY L. WHITLOCK - CENTERPOINT ENERGY RESOURCES CORP	ex31-2.htm
EX-32.2 - SECTION 1350 CERTIFICATION OF GARY L. WHITLOCK - CENTERPOINT ENERGY RESOURCES CORP	ex32-2.htm
EX-31.1 - RULE 13A-14(A)/15D-14(A) CERTIFICATION OF DAVID M. MCCLANAHAN - CENTERPOINT ENERGY RESOURCES CORP	ex31-1.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

	FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2009
OR
£	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	FOR THE TRANSITION PERIOD FROM TO

Commission file number 1-13265

CENTERPOINT ENERGY RESOURCES CORP.

(Exact name of registrant as specified in its charter)

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes £ No £

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

Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o
		(Do not check if a smaller reporting company)

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

As of October 19, 2009, all 1,000 shares of CenterPoint Energy Resources Corp. common stock were held by Utility Holding, LLC, a wholly owned subsidiary of CenterPoint Energy, Inc.

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CENTERPOINT ENERGY RESOURCES CORP.

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2009

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PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	1

	Condensed Statements of Consolidated Income
	Three and Nine months Ended September 30, 2008 and 2009 (unaudited)	1

	Condensed Consolidated Balance Sheets
	December 31, 2008 and September 30, 2009 (unaudited)	2

	Condensed Statements of Consolidated Cash Flows
	Nine months Ended September 30, 2008 and 2009 (unaudited)	4

	Notes to Unaudited Condensed Consolidated Financial Statements	5

Item 2.	Management’s Narrative Analysis of the Results of Operations	21

Item 4T.	Controls and Procedures	31

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	31

Item 1A.	Risk Factors	32

Item 5.	Other Information	38

Item 6.	Exhibits	38

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

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

•

state and federal legislative and regulatory actions or developments, including deregulation, re-regulation, environmental regulations, including regulations related to global climate change and health care reform, and changes in or application of laws or regulations applicable to the various aspects of our business;

•

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

•

cost overruns on major capital projects that cannot be recouped in prices;

•

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

•

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

•

the timing and extent of changes in the supply of natural gas, including supplies available for gathering by our field services business;

•

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

•

weather variations and other natural phenomena;

•

changes in interest rates or rates of inflation;

•

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

•

actions by rating agencies;

•

effectiveness of our risk management activities;

•

inability of various counterparties to meet their obligations to us;

•

non-payment for our services due to financial distress of our customers;

•

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

•

the outcome of litigation brought by or against us;

•

our ability to control costs;

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•

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

•

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

•

acquisition and merger activities involving our parent or our competitors; and

•

other factors we discuss in “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q and other reports we file from time to time with the Securities and Exchange Commission.

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

iii

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PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Millions of Dollars)

(Unaudited)

	Three Months Ended September 30,						Nine months Ended September 30,
	2008			2009			2008			2009

Revenues	$	1,960		$	965		$	7,069		$	4,432

Expenses:
Natural gas		1,532			582			5,675			3,081
Operation and maintenance		212			230			601			686
Depreciation and amortization		54			58			163			172
Taxes other than income taxes		33			31			129			126
Total		1,831			901			6,568			4,065

Operating Income		129			64			501			367

Other Income (Expense): Interest and other finance charges		(51	)		(52	)		(148	)		(159	)
Equity in earnings of unconsolidated affiliates		23			(3	)		46			8
Other, net		3			1			7			4
Total		(25	)		(54	)		(95	)		(147	)

Income Before Income Taxes		104			10			406			220
Income tax expense		(37	)		(5	)		(153	)		(86	)
Net Income	$	67		$	5		$	253		$	134

See Notes to the Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

(Unaudited)

ASSETS

	December 31, 2008		September 30, 2009
Current Assets:
Cash and cash equivalents	$	1	$	1
Accounts and notes receivable, net		774		331
Accrued unbilled revenue		480		99
Accounts and notes receivable – affiliated companies		9		15
Materials and supplies		54		78
Natural gas inventory		441		225
Non-trading derivative assets		118		50
Taxes receivable		—		144
Deferred tax asset, net		25		—
Prepaid expenses and other current assets		327		264
Total current assets		2,229		1,207

Property, Plant and Equipment:
Property, plant and equipment		6,313		6,743
Less accumulated depreciation and amortization		950		1,081
Property, plant and equipment, net		5,363		5,662

Other Assets:
Goodwill		1,696		1,696
Non-trading derivative assets		20		15
Investment in unconsolidated affiliates		345		471
Notes receivable from unconsolidated affiliates		323		—
Other		235		202
Total other assets		2,619		2,384

Total Assets	$	10,211	$	9,253

See Notes to the Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED BALANCE SHEETS — (Continued)

(Millions of Dollars)

(Unaudited)

LIABILITIES AND STOCKHOLDER’S EQUITY

	December 31, 2008			September 30, 2009
Current Liabilities:
Short-term borrowings	$	153		$	40
Current portion of long-term debt		7			7
Accounts payable		722			282
Accounts and notes payable — affiliated companies		33			270
Taxes accrued		99			74
Interest accrued		54			69
Customer deposits		59			65
Non-trading derivative liabilities		87			45
Other		302			235
Total current liabilities		1,516			1,087

Other Liabilities:
Accumulated deferred income taxes, net		864			1,052
Non-trading derivative liabilities		47			42
Benefit obligations		114			108
Regulatory liabilities		508			533
Other		101			142
Total other liabilities		1,634			1,877

Long-term Debt		3,712			2,805

Commitments and Contingencies (Note 11)

Stockholder’s Equity:
Common stock		—			—
Paid-in capital		2,416			2,416
Retained earnings		935			1,069
Accumulated other comprehensive loss		(2	)		(1	)
Total stockholder’s equity		3,349			3,484

Total Liabilities and Stockholder’s Equity	$	10,211		$	9,253

See Notes to the Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Millions of Dollars)

(Unaudited)

	Nine months Ended September 30,
	2008			2009
Cash Flows from Operating Activities:
Net income	$	253		$	134
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		163			172
Amortization of deferred financing costs		7			7
Deferred income taxes		62			235
Write-down of natural gas inventory		24			6
Equity in earnings of unconsolidated affiliates, net of distributions		(45	)		(4	)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net		469			819
Accounts receivable/payable, affiliates		40			(8	)
Inventory		(241	)		186
Taxes receivable		(26	)		(144	)
Accounts payable		(118	)		(440	)
Fuel cost over (under) recovery		(11	)		(53	)
Interest and taxes accrued		(23	)		(10	)
Non-trading derivatives, net		(22	)		26
Margin deposits, net		(96	)		89
Other current assets		20			23
Other current liabilities		(16	)		(2	)
Other assets		(1	)		4
Other liabilities		(37	)		(10	)
Other, net		(33	)		—
Net cash provided by operating activities		369			1,030

Cash Flows from Investing Activities:
Capital expenditures		(358	)		(458	)
Decrease (increase) in notes receivable from unconsolidated affiliates		(175	)		323
Investment in unconsolidated affiliates		(207	)		(111	)
Other, net		34			(3	)
Net cash used in investing activities		(706	)		(249	)

Cash Flows from Financing Activities:
Decrease in short-term borrowings, net		(82	)		(113	)
Long-term revolving credit facility, net		595			(916	)
Proceeds from commercial paper, net		—			15
Proceeds from long-term debt		300			—
Payments of long-term debt		(307	)		(6	)
Increase (decrease) in notes payable to affiliates		(67	)		239
Debt issuance costs		(2	)		—
Dividend to parent		(100	)		—
Net cash provided by (used in) financing activities		337			(781	)

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

Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	137		$	136
Income taxes		148			18
Non-cash transactions:
Accounts payable related to capital expenditures		54			51

See Notes to the Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1)	Background and Basis of Presentation

General. Included in this Quarterly Report on Form 10-Q (Form 10-Q) of CenterPoint Energy Resources Corp. (CERC Corp.) are the condensed consolidated interim financial statements and notes (Interim Condensed Financial Statements) of CenterPoint Energy Resources Corp. and its subsidiaries (collectively, CERC). The Interim Condensed Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the Annual Report on Form 10-K of CERC Corp. for the year ended December 31, 2008 (CERC Corp. Form 10-K).

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

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

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

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

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

(2)	New Accounting Pronouncements

Effective January 1, 2009, CERC adopted new accounting guidance which requires enhanced disclosures of derivative instruments and hedging activities such as the fair value of derivative instruments and presentation of their gains or losses in tabular format, as well as disclosures regarding credit risks and strategies and objectives for using derivative instruments. These disclosures are included as part of CERC’s Derivative Instruments footnote (see Note 5).

In December 2008, the FASB issued new accounting guidance on employers' disclosures about postretirement benefit plan assets which expands the disclosures about employers’ plan assets to include more detailed disclosures about the employers’ investment strategies, major categories of plan assets, concentrations of risk within plan assets and valuation techniques used to measure the fair value of plan assets. This new accounting guidance is effective for fiscal years ending after December 15, 2009. CERC expects that the adoption of this new guidance will not have a material impact on its financial position, results of operations or cash flows.

In April 2009, the FASB issued new accounting guidance on interim disclosures about fair value of financial instruments which expands the fair value disclosures required for all financial instruments to interim periods. This new guidance also requires entities to disclose in interim periods the methods and significant assumptions used to estimate the fair value of financial instruments. This new accounting guidance is effective for interim reporting periods ending after June 15, 2009. CERC’s adoption of this new guidance did not have a material impact on its financial position, results of operations or cash flows. See Note 13 for the required disclosures.

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In May 2009, the FASB issued new accounting guidance on subsequent events that establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. This new accounting guidance is effective for interim or annual periods ending after June 15, 2009. CERC’s adoption of this new guidance did not have a material impact on its financial position, results of operations or cash flows. See Note 16 for the subsequent event related disclosures.

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

In June 2009, the FASB issued new accounting guidance on the FASB Accounting Standards Codification (Codification) and the hierarchy of generally accepted accounting principles. This new accounting guidance establishes the Codification as the source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (SEC) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. This new accounting guidance is effective for financial statements issued for interim and annual periods ending after September 15, 2009. CERC’s adoption of this new guidance did not have any impact on its financial position, results of operations or cash flows.

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

(3)	Employee Benefit Plans

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

	Three Months Ended September 30,						Nine months Ended September 30,
	2008			2009			2008			2009
	(in millions)
Interest cost	$	2		$	2		$	6		$	6
Expected return on plan assets		(1	)		(1	)		(1	)		(1	)
Amortization of prior service cost		1			1			2			2
Net periodic cost	$	2		$	2		$	7		$	7

CERC expects to contribute approximately $16 million to CenterPoint Energy’s postretirement benefit plan in 2009, of which $4 million and $12 million, respectively, have been contributed during the three and nine months ended September 30, 2009.

(4)	Regulatory Matters

(a) Rate Proceedings

Texas. In March 2008, the natural gas distribution businesses of CERC (Gas Operations) filed a request to change its rates with the Railroad Commission of Texas (Railroad Commission) and the 47 cities in its Texas Coast service territory, an area consisting of approximately 230,000 customers in cities and communities on the outskirts of Houston. In 2008, Gas Operations implemented rates that are expected to increase annual revenues by approximately $3.5 million. The implemented rates have been contested by 9 cities. CERC does not expect the outcome of this matter to have a material adverse impact on its financial condition, results of operations or cash flows.

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In July 2009, Gas Operations filed a request to change its rates with the Railroad Commission and the 29 cities in its Houston service territory, consisting of approximately 940,000 customers in and around Houston. The request seeks to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Houston service territory. If approved by the Railroad Commission and the cities, the proposed new rates would result in an overall increase in annual revenue of $25.4 million. The proposed increase would allow Gas Operations to recover increased operating costs, which include higher pension expense. It would also provide a return on the additional capital invested to serve its customers. In addition, Gas Operations is seeking an adjustment mechanism similar to that obtained in the Texas Coast rate proceeding discussed above that would annually adjust rates to reflect changes in capital, expenses and usage. CERC does not expect an order from the Railroad Commission and the cities until the first quarter of 2010.

Minnesota. In November 2006, the Minnesota Public Utilities Commission (MPUC) denied a request filed by Gas Operations for a waiver of MPUC rules in order to allow Gas Operations to recover approximately $21 million in unrecovered purchased gas costs related to periods prior to July 1, 2004. Those unrecovered gas costs were identified as a result of revisions to previously approved calculations of unrecovered purchased gas costs. Following that denial, Gas Operations recorded a $21 million adjustment to reduce pre-tax earnings in the fourth quarter of 2006 and reduced the regulatory asset related to these costs by an equal amount. In March 2007, following the MPUC’s denial of reconsideration of its ruling, Gas Operations petitioned the Minnesota Court of Appeals for review of the MPUC’s decision, and in May 2008 that court ruled that the MPUC had been arbitrary and capricious in denying Gas Operations a waiver. The court ordered the case remanded to the MPUC for reconsideration under the same principles the MPUC had applied in previously granted waiver requests. The MPUC sought further review of the court of appeals decision from the Minnesota Supreme Court, and in July 2008, the Minnesota Supreme Court agreed to review the decision. In July 2009, the Minnesota Supreme Court issued its decision in which it reversed the decision of the Minnesota Court of Appeals and upheld the MPUC’s decision to deny the requested variance. The court’s decision had no negative impact on CERC’s financial condition, results of operations or cash flows, as the costs at issue were written off at the time they were disallowed.

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

Mississippi. In July 2009, Gas Operations filed a request with the Mississippi Public Service Commission (MPSC) to increase its rates by $6.2 million annually. In October 2009, the MPSC issued an order whereby Gas Operations would retain 100% of the benefits of an asset management agreement covering Mississippi pipeline and gas storage capacity, withdraw its request to increase base rates and not file another general rate increase, with certain exceptions, prior to July 1, 2011.

(b) Regulatory Accounting

CERC has a 50% ownership interest in Southeast Supply Header, LLC (SESH) which owns and operates a 270-mile interstate natural gas pipeline. In 2009, SESH discontinued the use of guidance for accounting for regulated operations, which resulted in CERC recording its share of the effects of such write-offs of SESH’s regulatory assets through non-cash pre-tax charges for the quarters ended March 31, 2009 and September 30, 2009 of $5 million and $11 million, respectively. These non-cash charges are reflected in equity in earnings of unconsolidated affiliates in the Condensed Statements of Consolidated Income. The related tax benefits of $2 million and $4 million, respectively, are reflected in the income tax expense line of the Condensed Statements of Consolidated Income.

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(5)	Derivative Instruments

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

In prior years, CERC entered into certain derivative instruments that were designated as cash flow hedges. The objective of these derivative instruments was to hedge the price risk associated with natural gas purchases and sales to reduce cash flow variability related to meeting CERC’s wholesale and retail customer obligations. If derivatives are designated as a cash flow hedge, the effective portions of the changes in their fair values are reflected initially as a separate component of stockholder’s equity and subsequently recognized in income at the same time the hedged items impact earnings. The ineffective portions of changes in fair values of derivatives designated as hedges are immediately recognized in income. Changes in derivatives not designated as normal or as cash flow hedges are recognized in income as they occur. CERC does not enter into or hold derivative instruments for trading purposes.

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

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

(a) Non-Trading Activities

Derivative Instruments. CERC enters into certain derivative instruments to manage physical commodity price risks that do not qualify or are not designated as cash flow or fair value hedges. CERC 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 September 30, 2008, CERC recorded increased natural gas revenues from unrealized net gains of $80 million and increased natural gas expense from unrealized net losses of $34 million, resulting in a net unrealized gain of $46 million. During the three months ended September 30, 2009, CERC recorded decreased natural gas revenues from unrealized net losses of $37 million and decreased natural gas expense from unrealized net gains of $31 million, resulting in a net unrealized loss of $6 million.

During the nine months ended September 30, 2008, CERC recorded increased natural gas revenues from unrealized net gains of $51 million and increased natural gas expense from unrealized net losses of $37 million, resulting in a net unrealized gain of $14 million. During the nine months ended September 30, 2009, CERC recorded decreased natural gas revenues from unrealized net losses of $71 million and decreased natural gas expense from unrealized net gains of $49 million, resulting in a net unrealized loss of $22 million.

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

In 2007, 2008 and 2009, CERC entered into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its financial position and cash flows for the respective winter heating seasons. The swaps were based on ten-year normal weather. During the three and nine months ended September 30, 2008, CERC recognized losses of $-0- and $13 million, respectively, related to these swaps. During the three and nine months ended September 30, 2009, CERC recognized

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losses of $-0- and $3 million, respectively, related to these swaps. The losses were substantially offset by increased revenues due to colder than normal weather. Weather hedge losses are included in revenues in the Condensed Statements of Consolidated Income.

(b) Derivative Fair Values and Income Statement Impacts

The following tables present information about CERC’s derivative instruments and hedging activities. The first table provides a balance sheet overview of CERC’s Derivative Assets and Liabilities as of September 30, 2009, while the latter tables provide a breakdown of the related income statement impact for the three and nine months ended September 30, 2009.

Fair Value of Derivative Instruments
	September 30, 2009
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value (2) (3)		Derivative Liabilities Fair Value (2) (3)
		(in millions)
Commodity contracts (1)	Current Assets	$	59	$	(9	)
Commodity contracts (1)	Other Assets		16		(1	)
Commodity contracts (1)	Current Liabilities		26		(137	)
Commodity contracts (1)	Other Liabilities		2		(94	)
Total		$	103	$	(241	)

_______

(1)

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

(2)

The fair value shown for commodity contracts is comprised of derivative gross volumes totaling 668 billion cubic feet (Bcf) or a net 138 Bcf long position. Of the net long position, basis swaps constitute 61 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment comprise 56 Bcf.

(3)

The net of total non-trading derivative assets and liabilities is a $22 million liability as shown on CERC’s Condensed Consolidated Balance Sheets, and is comprised of the commodity contracts derivative assets and liabilities separately shown above offset by collateral netting of $116 million.

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

Income Statement Impact of Derivative Activity
Total derivatives not designated as hedging instruments	Income Statement Location	Three Months Ended September 30, 2009
		(in millions)
Commodity contracts	Gains (Losses) in Revenue	$	(4	)
Commodity contracts (1)	Gains (Losses) in Expense: Natural Gas		(27	)
Total		$	(31	)

_________

(1)

The Gains (Losses) in Expense: Natural Gas includes $(31) million of costs associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered through purchased gas adjustments.

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Income Statement Impact of Derivative Activity
Total derivatives not designated as hedging instruments	Income Statement Location	Nine Months Ended September 30, 2009
		(in millions)
Commodity contracts	Gains (Losses) in Revenue	$	80
Commodity contracts (1)	Gains (Losses) in Expense: Natural Gas		(218	)
Total		$	(138	)

_________

(1)

The Gains (Losses) in Expense: Natural Gas includes $(148) million of costs associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered through purchased gas adjustments.

CERC enters into financial derivative contracts containing material adverse change provisions. These provisions require CERC to post additional collateral if the Standard & Poor’s Rating Services or Moody’s Investors Service, Inc. credit rating of CERC is downgraded. The total fair value of the derivative instruments that contain credit risk contingent features that are in a net liability position at September 30, 2009 is $151 million. The aggregate fair value of assets that are already posted as collateral at September 30, 2009 is $82 million. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at September 30, 2009, $69 million of additional assets would be required to be posted as collateral.

(6)	Fair Value Measurements

Effective January 1, 2008, CERC adopted new accounting guidance on fair value measurements which requires additional disclosures about CERC’s financial assets and liabilities that are measured at fair value. Effective January 1, 2009, CERC adopted this new guidance for nonfinancial assets and liabilities, which adoption had no impact on CERC’s financial position, results of operations or cash flows. Beginning in January 2008, assets and liabilities recorded at fair value in the Condensed Consolidated Balance Sheets are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined in this guidance and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities, are as follows:

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

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

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the level in the fair value hierarchy within which the fair value measurement in its entirety falls has been determined based on the lowest level input that is significant to the fair value measurement in its entirety. Unobservable inputs reflect CERC’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. CERC develops these inputs based on the best information available, including CERC’s own data. CERC’s Level 3 derivative instruments primarily consist of options that are not traded on recognized exchanges and are valued using option pricing models.

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The following tables present information about CERC’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of December 31, 2008 and September 30, 2009, and indicate the fair value hierarchy of the valuation techniques utilized by CERC to determine such fair value.

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of December 31, 2008
	(in millions)
Assets
Corporate equities	$	1	$	—	$	—	$	—		$	1
Investments, including money market funds		11		—		—		—			11
Derivative assets		8		155		49		(74	)		138
Total assets	$	20	$	155	$	49	$	(74	)	$	150
Liabilities
Derivative liabilities	$	44	$	244	$	107	$	(261	)	$	134
Total liabilities	$	44	$	244	$	107	$	(261	)	$	134

__________

(1)

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

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of September 30, 2009
	(in millions)
Assets
Corporate equities	$	1	$	—	$	—	$	—		$	1
Investments, including money market funds		11		—		—		—			11
Derivative assets		2		94		7		(38	)		65
Total assets	$	14	$	94	$	7	$	(38	)	$	77
Liabilities
Derivative liabilities	$	16	$	207	$	18	$	(154	)	$	87
Total liabilities	$	16	$	207	$	18	$	(154	)	$	87

__________

(1)

Amounts represent the impact of legally enforceable master netting agreements that allow CERC to settle positive and negative positions and also include cash collateral of $116 million posted with the same counterparties.

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

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	Three Months Ended September 30,
	2008			2009
	(in millions)
Beginning balance	$	6		$	(17	)
Total unrealized gains or (losses):
Included in earnings		(61	)		2
Included in regulatory assets		—			3
Purchases, sales, other settlements, net		(4	)		1	(1)
Ending balance	$	(59	)	$	(11	)
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	4		$	3

__________

(1)	Purchases, sales, other settlements, net include a less than $1 million gain associated with price stabilization activities of CERC’s Natural Gas Distribution business segment.

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	Nine Months Ended September 30,
	2008			2009
	(in millions)
Beginning balance	$	(3	)	$	(58	)
Total unrealized gains or (losses):
Included in earnings		(52	)		—
Included in regulatory assets		—			(13	)
Purchases, sales, other settlements, net		(4	)		60	(1)
Ending balance	$	(59	)	$	(11	)
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	9		$	2

_________

(1)

Purchases, sales, other settlements, net include a $57 million gain associated with price stabilization activities of CERC’s Natural Gas Distribution business segment.

(7)

Goodwill

Goodwill by reportable business segment as of both December 31, 2008 and September 30, 2009 is as follows (in millions):

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

CERC performs its goodwill impairment tests at least annually and evaluates goodwill when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The impairment evaluation for goodwill is performed by using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is

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generally determined on the basis of discounted future cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed in order to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference.

CERC performed the test at July 1, 2009, its annual impairment testing date, and determined that no impairment charge for goodwill was required.

(8)	Comprehensive Income

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

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2008			2009		2008			2009
	(in millions)
Net income	$	67		$	5	$	253		$	134
Other comprehensive income (loss):
Adjustment to pension and other postretirement plans (net of tax of $1, $-0-, $1 and $1)		(1	)		—		(1	)		1
Reclassification of deferred gain from cash flow hedges realized in net income (net of tax of $-0-, $-0-,$2, $-0-)		(1	)		—		(5	)		—
Other comprehensive income (loss)		(2	)		—		(6	)		1
Comprehensive income	$	65		$	5	$	247		$	135

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

	December 31, 2008			September 30, 2009
	(in millions)
Adjustment to pension and other postretirement plans		(2	)		(1	)
Total accumulated other comprehensive income	$	(2	)	$	(1	)

(9)	Related Party Transactions

CERC participates in a “money pool” through which it can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings by CenterPoint Energy under its revolving credit facility or the sale by CenterPoint Energy of its commercial paper. As of December 31, 2008 and September 30, 2009, CERC had borrowings from the money pool of $-0- and $239 million, respectively.

For both the three months ended September 30, 2008 and 2009, CERC had net interest expense related to affiliate borrowings of less than $1 million. For the nine months ended September 30, 2008 and 2009, CERC had net interest expense related to affiliate borrowings of approximately $1 million and less than $1 million, respectively.

CenterPoint Energy provides some corporate services to CERC. The costs of services have been charged directly to CERC using methods that management believes are reasonable. These methods include negotiated usage rates, dedicated asset assignment and proportionate corporate formulas based on operating expenses, assets, gross margin, employees and a composite of assets, gross margin and employees. These charges are not necessarily indicative of what would have been incurred had CERC not been an affiliate. Amounts charged to CERC for these services were $35 million and $39 million for the three months ended September 30, 2008 and 2009, respectively, and $105 million and $115 million for the nine months ended September 30, 2008 and 2009, respectively, and are included primarily in operation and maintenance expenses.

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

(a) Short-term Borrowings

Receivables Facility. On October 9, 2009, CERC amended its receivables facility to extend the termination date to October 8, 2010. Availability under CERC’s 364-day receivables facility now ranges from $150 million to $375 million, reflecting seasonal changes in receivables balances. As of December 31, 2008 and September 30, 2009, the facility size was $128 million and $150 million, respectively. As of December 31, 2008 and September 30, 2009, advances under the receivables facilities were $78 million and $40 million, respectively.

Inventory Financing. In December 2008, CERC entered into an asset management agreement whereby it sold $110 million of its natural gas in storage and agreed to repurchase an equivalent amount of natural gas during the 2008-2009 winter heating season for payments totaling $114 million. This transaction was accounted for as a financing and, as of December 31, 2008 and September 30, 2009, CERC’s financial statements reflect natural gas inventory of $75 million and $-0-, respectively, and a financing obligation of $75 million and $-0-, respectively, related to this transaction.

(b) Long-term Debt

Revolving Credit Facility. On October 7, 2009, the size of the CERC Corp. revolving credit facility was reduced from $950 million to $915 million through removal of Lehman Brothers Bank, FSB (Lehman) as a lender. Prior to its removal, Lehman had a $35 million commitment to lend. All credit facility loans to CERC Corp. that were funded by Lehman were repaid in September 2009. CERC Corp.’s $915 million credit facility’s first drawn cost is the London Interbank Offered Rate (LIBOR) plus 45 basis points based on CERC Corp.’s current credit ratings. The facility contains a debt to total capitalization covenant.

Under CERC Corp.’s $915 million credit facility, an additional utilization fee of 5 basis points applies to borrowings any time more than 50% of the facility is utilized. The spread to LIBOR and the utilization fee fluctuate based on CERC Corp.’s credit rating.

As of December 31, 2008 and September 30, 2009, CERC Corp. had $926 million and $10 million, respectively, of borrowings under its $915 million credit facility. There was $-0- and $15 million of outstanding commercial paper backstopped by CERC Corp.’s credit facility as of December 31, 2008 and September 30, 2009, respectively. CERC Corp. was in compliance with all debt covenants as of September 30, 2009.

(11)	Commitments and Contingencies

(a) Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to CERC’s Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in CERC’s Condensed Consolidated Balance Sheets as of December 31, 2008 and September 30, 2009 as these contracts meet the exception to be classified as "normal purchases contracts" or do not meet the definition of a derivative. Natural gas supply commitments also include natural gas transportation contracts that do not meet the definition of a derivative. As of September 30, 2009, minimum payment obligations for natural gas supply commitments are approximately $151 million for the remaining three months in 2009, $449 million in 2010, $466 million in 2011, $383 million in 2012, $371 million in 2013 and $738 million after 2013.

(b) Capital Commitments

In September 2009, CenterPoint Energy Field Services, Inc. (CEFS), a wholly-owned natural gas gathering and treating subsidiary of CERC Corp., entered into long-term agreements with an indirect wholly-owned subsidiary of EnCana Corporation (EnCana) and an indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide gathering and treating services for their natural gas production from the Haynesville Shale and Bossier Shale formations in Texas and Louisiana. CEFS has also acquired existing jointly-owned gathering facilities from EnCana and Shell in De Soto and Red River parishes in northwest Louisiana.

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Under the terms of the agreements, CEFS commenced gathering and treating services immediately utilizing the acquired facilities. CEFS will also expand the acquired facilities to gather and treat up to 700 million cubic feet (MMcf) per day of natural gas from their current throughput of over 100 MMcf per day. If EnCana or Shell elect, CEFS will further expand the facilities in order to gather and treat additional future volumes.

New construction to reach capacity of 700 MMcf per day includes more than 200 miles of pipelines, nearly 25,500 horsepower of compression and over 800 MMcf per day of treating capacity.

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

CEFS estimates that the purchase of existing facilities and construction to gather 700 MMcf per day will cost up to $325 million. If EnCana and Shell elect expansion of the project to gather and process additional future volumes of up to 1 billion cubic feet per day, CEFS estimates that the expansion would cost as much as an additional $300 million and EnCana and Shell would provide incremental volume commitments.

Legal Matters

Gas Market Manipulation Cases. CenterPoint Energy or its predecessor, Reliant Energy, Incorporated (Reliant Energy), and certain of its former subsidiaries are named as defendants in several lawsuits described below. Under a master separation agreement between CenterPoint Energy and RRI (formerly known as Reliant Resources, Inc. and Reliant Energy, Inc.), CenterPoint Energy and its subsidiaries are entitled to be indemnified by RRI for any losses, including attorneys’ fees and other costs, arising out of these lawsuits. Pursuant to the indemnification obligation, RRI is defending CenterPoint Energy and its subsidiaries to the extent named in these lawsuits. A large number of lawsuits were filed against numerous gas market participants in a number of federal and western state courts in connection with the operation of the natural gas markets in 2000-2002. CenterPoint Energy’s former affiliate, RRI, was a participant in gas trading in the California and Western markets. These lawsuits, many of which have been filed as class actions, allege violations of state and federal antitrust laws. Plaintiffs in these lawsuits are seeking a variety of forms of relief, including, among others, recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages, full consideration damages and attorneys’ fees. CenterPoint Energy and/or Reliant Energy were named in approximately 30 of these lawsuits, which were instituted between 2003 and 2009. CenterPoint Energy and its affiliates have been released or dismissed from all but two of such cases. CenterPoint Energy Services, Inc. (CES), a subsidiary of CERC Corp., is a defendant in a case now pending in federal court in Nevada alleging a conspiracy to inflate Wisconsin natural gas prices in 2000-2002. Additionally, CenterPoint Energy was a defendant in a lawsuit filed in state court in Nevada that was dismissed in 2007, but the plaintiffs have indicated that they will appeal the dismissal. CenterPoint Energy believes that neither it nor CES is a proper defendant in these remaining cases and will continue to pursue dismissal from those cases. CERC does not expect the ultimate outcome of these remaining matters to have a material impact on its financial condition, results of operations or cash flows.

On May 1, 2009, RRI completed the previously announced sale of its Texas retail business to NRG Retail LLC, a subsidiary of NRG Energy, Inc. In connection with the sale, RRI changed its name to RRI Energy, Inc. The sale does not alter RRI’s contractual obligations to indemnify CenterPoint Energy and its subsidiaries for certain liabilities, including their indemnification regarding certain litigation, nor does it affect the terms of existing guaranty arrangements for certain RRI gas transportation contracts.

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

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the ground that the court lacked subject matter jurisdiction over the claims asserted. The plaintiff sought review of that dismissal from the Tenth Circuit Court of Appeals, which affirmed the district court’s dismissal in March 2009. Following dismissal of the plaintiff's motion to the Tenth Circuit for rehearing, the plaintiff sought review by the United States Supreme Court, but his petition for certiorari was denied in October 2009.

In addition, CERC Corp. and certain of its subsidiaries are defendants in two mismeasurement lawsuits brought against approximately 245 pipeline companies and their affiliates pending in state court in Stevens County, Kansas. In one case (originally filed in May 1999 and amended four times), the plaintiffs purport to represent a class of royalty owners who allege that the defendants have engaged in systematic mismeasurement of the volume of natural gas for more than 25 years. The plaintiffs amended their petition in this suit in July 2003 in response to an order from the judge denying certification of the plaintiffs’ alleged class. In the amendment the plaintiffs dismissed their claims against certain defendants (including two CERC Corp. subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the British thermal unit (Btu) content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a putative class of royalty owners, in which they assert their claims that the defendants have engaged in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. In September 2009, the district court in Stevens County, Kansas, denied plaintiffs' request for class certification of their case, but the plaintiffs have sought rehearing of that dismissal.

CERC believes that there has been no systematic mismeasurement of gas and that these lawsuits are without merit. CERC 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 2004, a lawsuit was filed by certain CERC ratepayers in Texas and Arkansas in circuit court in Miller County, Arkansas against CERC Corp., CenterPoint Energy, Entex Gas Marketing Company (EGMC), CenterPoint Energy Gas Transmission Company (CEGT), CenterPoint Energy Field Services (CEFS), CenterPoint Energy Pipeline Services, Inc. (CEPS), Mississippi River Transmission Corp. (MRT) and various non-affiliated companies alleging fraud, unjust enrichment and civil conspiracy with respect to rates charged to certain consumers of natural gas in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. Subsequently, the plaintiffs dropped CEGT and MRT as defendants. Although the plaintiffs in the Miller County case sought class certification, no class was certified. In June 2007, the Arkansas Supreme Court determined that the Arkansas claims were within the sole and exclusive jurisdiction of the Arkansas Public Service Commission (APSC). In response to that ruling, in August 2007 the Miller County court stayed but refused to dismiss the Arkansas claims. In February 2008, the Arkansas Supreme Court directed the Miller County court to dismiss the entire case for lack of jurisdiction. The Miller County court subsequently dismissed the case in accordance with the Arkansas Supreme Court’s mandate and all appellate deadlines have expired.

In June 2007, CenterPoint Energy, CERC Corp., EGMC and other defendants in the Miller County case filed a petition in a district court in Travis County, Texas seeking a determination that the Railroad Commission has exclusive original jurisdiction over the Texas claims asserted in the Miller County case. In October 2007, CEFS and CEPS joined the petition in the Travis County case. In October 2008, the district court ruled that the Railroad Commission had exclusive original jurisdiction over the Texas claims asserted against CenterPoint Energy, CERC Corp., EGMC and the other defendants in the Miller County case. In January 2009, the court entered a final declaratory judgment ruling that the Railroad Commission has exclusive jurisdiction over Texas claims. All appellate deadlines expired without an appeal of the final declaratory judgment.

In August 2007, the Arkansas plaintiff in the Miller County litigation initiated a complaint at the APSC seeking a decision concerning the extent of the APSC’s jurisdiction over the Miller County case and an investigation into the merits of the allegations asserted in his complaint with respect to CERC. In February 2009, the Arkansas plaintiff notified the APSC that he would no longer pursue his claims, and in July 2009 the complaint proceeding was dismissed by the APSC. All appellate deadlines expired without an appeal of the dismissal order.

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Environmental Matters

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

At September 30, 2009, CERC had accrued $14 million for remediation of these Minnesota sites and the estimated range of possible remediation costs for these sites was $4 million to $35 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. CERC has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. As of September 30, 2009, CERC had collected $13 million from insurance companies and rate payers to be used for future environmental remediation.

In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CERC has been named as a defendant in a lawsuit filed in the United States District Court, District of Maine, under which contribution is sought by private parties for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of CERC or its divisions. CERC has also been identified as a PRP by the State of Maine for a site that is the subject of the lawsuit. In June 2006, the federal district court in Maine ruled that the current owner of the site is responsible for site remediation but that an additional evidentiary hearing is required to determine if other potentially responsible parties, including CERC, would have to contribute to that remediation. CERC believes it is not liable as a former owner or operator of the site under the Comprehensive Environmental, Response, Compensation and Liability Act of 1980, as amended, and applicable state statutes, and is vigorously contesting the suit and its designation as a PRP. In September 2009, the federal district court granted CERC’s motion for summary judgment in the proceeding. Although it is likely that the plaintiff will pursue an appeal from that dismissal, further action will not be taken until the district court disposes of claims against other defendants in the case. CERC does not expect the ultimate outcome to have a material impact on its financial condition, results of operations or cash flows.

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

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

Groundwater Contamination Litigation. Predecessor entities of CERC, along with several other entities, are defendants in litigation, St. Michel Plantation, LLC, et al, v. White, et al., pending in civil district court in Orleans Parish, Louisiana. In the lawsuit, the plaintiffs allege that their property in Terrebonne Parish, Louisiana suffered salt water contamination as a result of oil and gas drilling activities conducted by the defendants. Although a predecessor of CERC held an interest in two oil and gas leases on a portion of the property at issue, neither it nor any other CERC entities drilled or conducted other oil and gas operations on those leases. In January 2009, CERC

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and the plaintiffs reached agreement on the terms of a settlement that, if ultimately approved by the Louisiana Department of Natural Resources, is expected to resolve this litigation. CERC does not expect the outcome of this litigation to have a material adverse impact on its financial condition, results of operations or cash flows.

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

Other Proceedings

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

(d) Guaranties

Prior to CenterPoint Energy’s distribution of its ownership in RRI to its shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure CERC against obligations under the guaranties RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI has agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guaranties for demand charges under certain gas purchase and transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guaranties. As of September 30, 2009, RRI was not required to provide security to CERC. If RRI should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, collateral provided as security may be insufficient to satisfy CERC’s obligations.

(12)	Income Taxes

During the three months and nine months ended September 30, 2008, the effective tax rate was 36% and 38%, respectively. During the three months and nine months ended September 30, 2009, the effective tax rate was 49% and 39%, respectively. Lower pre-tax income in 2009 primarily affected the comparability of the effective tax rate for the three months ended September 30, 2008 and 2009.

The following table summarizes CERC’s uncertain tax positions at December 31, 2008 and September 30, 2009:

	December 31, 2008			September 30, 2009
	(in millions)
Liability (receivable) for uncertain tax positions	$	(12	)	$	8
Portion of receivable for uncertain tax positions that, if recognized, would reduce the effective income tax rate		1			-
Interest accrued on uncertain tax positions		(4	)		(5	)

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(13)	Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents, investments in debt and equity securities classified as "available-for-sale" and "trading" and short-term borrowings are estimated to be approximately equivalent to carrying amounts and have been excluded from the table below. The fair values of non-trading derivative assets and liabilities are equivalent to their carrying amounts in the Condensed Consolidated Balance Sheets at December 31, 2008 and September 30, 2009 and have been determined using quoted market prices for the same or similar instruments when available or other estimation techniques (see Notes 5 and 6). Therefore, these financial instruments are stated at fair value and are excluded from the table below. The fair value of each debt instrument is determined by multiplying the principal amount of each debt instrument by the market price.

	December 31, 2008				September 30, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Financial liabilities:
Long-term debt	$	3,719	$	3,568	$	2,812	$	2,939

(14)	Reportable Business Segments

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

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

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

	For the Three Months Ended September 30, 2008
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)
Natural Gas Distribution	$	548	$	2		$	(6	)
Competitive Natural Gas Sales and Services		1,256		13			35
Interstate Pipelines		96		47			55	(1)
Field Services		60		11			44
Other Operations		—		—			1
Eliminations		—		(73	)		—
Consolidated	$	1,960	$	—		$	129

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	For the Three Months Ended September 30, 2009
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)
Natural Gas Distribution	$	400	$	2		$	(15	)
Competitive Natural Gas Sales and Services		395		4			(8	)
Interstate Pipelines		119		34			64
Field Services		51		12			23
Other Operations		—		—			—
Eliminations		—		(52	)		—
Consolidated	$	965	$	—		$	64

	For the Nine Months Ended September 30, 2008
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2008
Natural Gas Distribution	$	2,969	$	7		$	119		$	4,961
Competitive Natural Gas Sales and Services		3,599		33			36			1,315
Interstate Pipelines		337		131			227	(1)		3,578
Field Services		164		27			121	(2)		826
Other Operations		—		—			(2	)		724
Eliminations		—		(198	)		—			(1,193	)
Consolidated	$	7,069	$	—		$	501		$	10,211

	For the Nine Months Ended September 30, 2009
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)			Total Assets as of September 30, 2009
Natural Gas Distribution	$	2,334	$	7		$	105		$	4,281
Competitive Natural Gas Sales and Services		1,585		11			—			1,065
Interstate Pipelines		355		106			194			3,478
Field Services		158		18			72			934
Other Operations		—		—			(4	)		404
Eliminations		—		(142	)		—			(909	)
Consolidated	$	4,432	$	—		$	367		$	9,253

(1)

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

(2)

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

(15)	Other Currents Assets and Liabilities

Included in other current assets on the Condensed Consolidated Balance Sheets at December 31, 2008 and September 30, 2009 was $128 million and $81 million, respectively of under-recovered gas cost. Included in other current liabilities on the Condensed Consolidated Balance Sheets at December 31, 2008 and September 30, 2009 was $79 million and $21 million, respectively, of over recovered gas cost.

(16)	Subsequent Events

CERC has evaluated all subsequent events through the date these Interim Condensed Financial Statements were issued, which was November 10, 2009.

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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 and our Annual Report on Form 10-K for the year ended December 31, 2008 (2008 Form 10-K).

We meet the conditions specified in General Instruction H(1)(a) and (b) to Form 10-Q and are therefore permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies. Accordingly, we have omitted from this report the information called for by Item 2 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Item 3 (Quantitative and Qualitative Disclosures About Market Risk) of Part I and the following Part II items of Form 10-Q: Item 2 (Unregistered Sales of Equity Securities and Use of Proceeds), Item 3 (Defaults Upon Senior Securities) and Item 4 (Submission of Matters to a Vote of Security Holders). The following discussion explains material changes in our revenue and expense items between the three and nine months ended September 30, 2008 and the three and nine months ended September 30, 2009. Reference is made to “Management’s Narrative Analysis of Results of Operations” in Item 7 of our 2008 Form 10-K.

EXECUTIVE SUMMARY

Recent Events

Long-Term Gas Gathering and Treatment Agreements

In September 2009, CenterPoint Energy Field Services, Inc. (CEFS), our wholly-owned natural gas gathering and treating subsidiary, entered into long-term agreements with an indirect wholly-owned subsidiary of EnCana Corporation (EnCana) and an indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide gathering and treating services for their natural gas production from the Haynesville Shale and Bossier Shale formations in Texas and Louisiana. CEFS has also acquired existing jointly-owned gathering facilities from EnCana and Shell in De Soto and Red River parishes in northwest Louisiana.

New construction to reach capacity of 700 MMcf per day includes more than 200 miles of pipelines, nearly 25,500 horsepower of compression and over 800 MMcf per day of treating capacity.

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

CEFS estimates that the purchase of existing facilities and construction to gather 700 MMcf per day will cost up to $325 million. If EnCana and Shell elect expansion of the project to gather and process additional future volumes of up to 1 billion cubic feet per day (Bcf), CEFS estimates that the expansion would cost as much as an additional $300 million and EnCana and Shell would provide incremental volume commitments. Funds for construction will be provided from anticipated cash flows from operations, lines of credit or proceeds from the sale of debt or equity securities.

Debt Transactions

On August 13, 2009, Southeast Supply Header, LLC (SESH) issued $375 million of 4.85% senior notes due 2014. SESH used one-half of the proceeds of the notes to repay a construction loan to us in the amount of $186 million. We used the proceeds from the construction loan repayment to repay borrowings under CERC Corp.’s credit facility.

On October 7, 2009, the size of CERC Corp.’s revolving credit facility was reduced from $950 million to $915 million through removal of Lehman Brothers Bank, FSB (Lehman) as a lender. Prior to its removal, Lehman had a $35 million commitment to lend. All credit facility loans to CERC Corp. that were funded by Lehman were repaid in September 2009.

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On October 9, 2009, we amended our receivables facility to extend the termination date to October 8, 2010. Availability under our 364-day receivables facility ranges from $150 million to $375 million, reflecting seasonal changes in receivables balances.

Asset Management Agreements

Our natural gas distribution businesses (Gas Operations) entered into various asset management agreements associated with its utility distribution service in Arkansas, Oklahoma, Louisiana, Mississippi and Texas. Generally, an asset management agreement is a contract between an asset holder and an asset manager that strives to maximize the revenue-earning potential of the asset. In these agreements, Gas Operations agreed to release transportation and storage capacity to another party to manage gas storage, supply and delivery arrangements for Gas Operations when the released capacity is not needed and thereby maximize the value of the assets. Gas Operations will be compensated by the asset manager, in part based on the results of the asset optimization, and entering into the asset management agreements will reduce working capital requirements. The agreements are expected, subject to regulatory approval, to commence in the fourth quarter of 2009 and to continue for various terms extending up to 2016.

Gas Operations has filed applications with state regulatory commissions in Arkansas, Louisiana, Mississippi and Oklahoma for approval of the applicable asset management agreements and to retain a share of the proceeds, with the remainder to benefit customers. Commission approval has been obtained in Louisiana, Oklahoma, Mississippi and for one of two agreements in Arkansas. A filing is expected to be made in Texas in the fourth quarter of 2009.

CONSOLIDATED RESULTS OF OPERATIONS

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

The following table sets forth our consolidated results of operations for the three and nine months ended September 30, 2008 and 2009, followed by a discussion of our consolidated results of operations.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2009			2008			2009
	(in millions)
Revenues	$	1,960		$	965		$	7,069		$	4,432
Expenses:
Natural gas		1,532			582			5,675			3,081
Operation and maintenance		212			230			601			686
Depreciation and amortization		54			58			163			172
Taxes other than income taxes		33			31			129			126
Total Expenses		1,831			901			6,568			4,065
Operating Income		129			64			501			367
Interest and Other Finance Charges		(51	)		(52	)		(148	)		(159	)
Equity in earnings of unconsolidated affiliates		23			(3	)		46			8
Other Income, net		3			1			7			4
Income Before Income Taxes		104			10			406			220
Income Tax Expense		(37	)		(5	)		(153	)		(86	)
Net Income	$	67		$	5		$	253		$	134

Three months ended September 30, 2009 compared to three months ended September 30, 2008

We reported net income of $5 million for the three months ended September 30, 2009 compared to $67 million for the same period in 2008. The decrease in net income of $62 million was primarily due to a $65 million decrease

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in operating income from our business segments as discussed below and a $26 million decrease in equity in earnings of unconsolidated affiliates, partially offset by a $32 million decrease in income tax expense.

Nine months ended September 30, 2009 compared to nine months ended September 30, 2008

We reported net income of $134 million for the nine months ended September 30, 2009 compared to $253 million for the same period in 2008. The decrease in net income of $119 million was primarily due to a $134 million decrease in operating income from our business segments as discussed below, a $38 million decrease in equity in earnings of unconsolidated affiliates and an $11 million increase in interest and other finance charges, partially offset by a $67 million decrease in income tax expense.

Income Tax Expense. During the three months and nine months ended September 30, 2008, the effective tax rate was 36% and 38%, respectively. During the three months and nine months ended September 30, 2009, the effective tax rate was 49% and 39%, respectively. Lower pre-tax income in 2009 primarily affected the comparability of the effective tax rate for the three months ended September 30, 2008 and 2009.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (loss) for each of our business segments for the three and nine months ended September 30, 2008 and 2009 (in millions), followed by a discussion of the results of operations by business segment based on operating income. Included in revenues are intersegment sales. We account for intersegment sales as if the sales were to third parties, that is, at current market prices.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2009			2008			2009
Natural Gas Distribution	$	(6	)	$	(15	)	$	119		$	105
Competitive Natural Gas Sales and Services		35			(8	)		36			—
Interstate Pipelines		55			64			227			194
Field Services		44			23			121			72
Other Operations		1			—			(2	)		(4	)
Total Consolidated Operating Income	$	129		$	64		$	501		$	367

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Natural Gas Distribution

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

The following table provides summary data of our Natural Gas Distribution business segment for the three and nine months ended September 30, 2008 and 2009 (in millions, except throughput and customer data):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2009			2008		2009
Revenues	$	550		$	402		$	2,976	$	2,341
Expenses:
Natural gas		351			198			2,196		1,538
Operation and maintenance		139			157			436		478
Depreciation and amortization		40			40			118		121
Taxes other than income taxes		26			22			107		99
Total expenses		556			417			2,857		2,236
Operating Income (Loss)	$	(6	)	$	(15	)	$	119	$	105

Throughput (in Bcf):
Residential		13			13			117		111
Commercial and industrial		41			38			171		154
Total Throughput		54			51			288		265

Number of customers at period end:
Residential		2,936,777			2,954,095			2,936,777		2,954,095
Commercial and industrial		244,959			241,036			244,959		241,036
Total		3,181,736			3,195,131			3,181,736		3,195,131

Three months ended September 30, 2009 compared to three months ended September 30, 2008

Our Natural Gas Distribution business segment reported an operating loss of $15 million for the three months ended September 30, 2009 compared to an operating loss of $6 million for the three months ended September 30, 2008. Operating margin (revenues less cost of gas) increased $5 million primarily due to increased rates ($4 million). Operation and maintenance expenses increased $18 million primarily due to increased pension expense ($8 million), higher labor and non-pension related benefits expense ($4 million), customer related expenses and support services costs ($5 million) and increases in other expenses ($4 million), partially offset by lower bad debt expense ($4 million). Taxes other than income taxes decreased primarily due to lower gross receipts taxes.

Nine months ended September 30, 2009 compared to nine months ended September 30, 2008

Our Natural Gas Distribution business segment reported operating income of $105 million for the nine months ended September 30, 2009 compared to operating income of $119 million for the nine months ended September 30, 2008. Operating margin improved $23 million primarily as a result of rate increases ($18 million), recovery of higher energy-efficiency costs ($4 million), increased non-utility revenues ($5 million), residential customer growth ($2 million), with the addition of approximately 17,000 customers, and increased margin from commercial and industrial customers ($2 million), partially offset by decreased gross receipts taxes ($10 million). Operation and maintenance expenses increased $42 million primarily due to increased pension expense ($26 million), higher labor and non-pension related benefits expense ($11 million) and increased customer-related expenses and support services costs ($11 million), partially offset by lower bad debt expense ($8 million) and other expense reductions ($3 million). Depreciation expense increased due to higher plant balances. Taxes other than income taxes decreased due to the gross receipts taxes above, partially offset by an increase in property taxes ($2 million).

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Competitive Natural Gas Sales and Services

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

The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for the three and nine months ended September 30, 2008 and 2009 (in millions, except throughput and customer data):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2008		2009			2008		2009
Revenues	$	1,269	$	399		$	3,632	$	1,596
Expenses:
Natural gas		1,225		396			3,567		1,562
Operation and maintenance		8		10			26		30
Depreciation and amortization		1		1			2		3
Taxes other than income taxes		-		-			1		1
Total expenses		1,234		407			3,596		1,596
Operating Income (Loss)	$	35	$	(8	)	$	36	$	-

Throughput (in Bcf)		125		115			392		370

Number of customers at period end		8,988		10,934			8,988		10,934

Three months ended September 30, 2009 compared to three months ended September 30, 2008

Our Competitive Natural Gas Sales and Services business segment reported an operating loss of $8 million for the three months ended September 30, 2009 compared to operating income of $35 million for the three months ended September 30, 2008. The decrease in operating income of $43 million was primarily due to the unfavorable impact of mark-to-market accounting for non-trading financial derivatives for the third quarter of 2009 of $6 million versus a favorable impact of $46 million for the same period in 2008. Our Competitive Natural Gas Sales and Services business segment purchases and stores natural gas to meet certain future sales requirements and enters into derivative contracts to hedge the economic value of the future sales. The derivative contracts create the mark-to-market accounting adjustment. This decrease was partially offset by the absence of a write-down of natural gas inventory to the lower of cost or market in the current quarter as compared to a $24 million write-down in the third quarter 2008. The remaining $15 million decrease was comprised of reduced margin of $12 million, due to lower sales volume and reduced locational spreads and increased operating expense of $3 million.

Nine months ended September 30, 2009 compared to nine months ended September 30, 2008

Our Competitive Natural Gas Sales and Services business segment reported operating income of $-0- for the nine months ended September 30, 2009 compared to operating income of $36 million for the nine months ended September 30, 2008. The decrease in operating income of $36 million was primarily due to the unfavorable impact of the mark-to-market valuation for non-trading financial derivatives for the first nine months of 2009 of $22 million versus a favorable impact of $14 million for the same period in 2008. This decrease in operating income was partially offset by a $6 million write-down of natural gas inventory to the lower of cost or market for the nine months ended September 30, 2009 compared to a $24 million write-down in the same period last year. The remaining $18 million decrease was comprised of reduced margin of $13 million and increased operating expense of $5 million for the nine months ended September 30, 2009 compared to the same period last year.

Interstate Pipelines

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

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The following table provides summary data of our Interstate Pipelines business segment for the three and nine months ended September 30, 2008 and 2009 (in millions, except throughput data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2009		2008		2009
Revenues	$	143	$	153	$	468	$	461
Expenses:
Natural gas		24		22		97		85
Operation and maintenance		47		47		93		123
Depreciation and amortization		11		12		34		36
Taxes other than income taxes		6		8		17		23
Total expenses		88		89		241		267
Operating Income	$	55	$	64	$	227	$	194

Transportation throughput (in Bcf) :		360		378		1,145		1,235

Three months ended September 30, 2009 compared to three months ended September 30, 2008

Our Interstate Pipeline business segment reported operating income of $64 million for the three months ended September 30, 2009 compared to $55 million for the three months ended September 30, 2008. Margins (revenues less natural gas costs) increased $12 million primarily due to a new backhaul agreement on the Carthage to Perryville pipeline ($10 million) and new contracts with power generation customers ($6 million). These increases were partially offset by reduced other transportation margins and ancillary services ($4 million) primarily due to the decline in commodity prices from the significantly higher levels in 2008. Operations and maintenance expenses increased due to costs associated with incremental facilities and increased pension expenses ($7 million), but that increase was offset by a write-down associated with pipeline assets removed from service in the third quarter of 2008 ($7 million). Depreciation and amortization expenses increased $1 million and taxes other than income increased by $2 million, $1 million of which was due to 2008 tax refunds.

Equity Earnings. In addition, this business segment recorded equity income of $18 million and equity loss of $5 million for the three months ended September 30, 2008 and 2009, respectively, from its 50 percent interest in SESH, a jointly-owned pipeline that went into service in September 2008. Approximately $17 million of income in the third quarter of 2008 was pre-operating allowance for funds used during construction in 2008. The third quarter 2009 loss of $5 million included a non-cash pre-tax charge of $11 million associated with the write-off of certain regulatory assets resulting from SESH’s decision to discontinue the use of guidance for accounting for regulated operations. The charge more than offset the equity income from SESH’s ongoing operations of $6 million for the third quarter of 2009. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Nine months ended September 30, 2009 compared to nine months ended September 30, 2008

Our Interstate Pipeline business segment reported operating income of $194 million for the nine months ended September 30, 2009 compared to $227 million for the nine months ended September 30, 2008. Margins (revenues less natural gas costs) increased $5 million primarily due to the Carthage to Perryville pipeline ($22 million) and new contracts with power generation customers ($15 million). These increases were partially offset by reduced other transportation margins and ancillary services ($32 million) primarily due to the decline in commodity prices from the significantly higher levels in 2008. Operations and maintenance expenses increased primarily due to a gain on the sale of two storage development projects in 2008 ($18 million) and costs associated with incremental facilities and increased pension expenses ($19 million). These expenses were partially offset by a write-down associated with pipeline assets removed from service in the third quarter of 2008 ($7 million). Depreciation and amortization expenses increased $2 million and taxes other than income increased by $6 million, $3 million of which was due to 2008 tax refunds.

Equity Earnings. In addition, this business segment recorded equity income of $34 million and $2 million for the nine months ended September 30, 2008 and 2009, respectively, from its 50 percent interest in SESH. Approximately $33 million of the income in the nine months ended September 30, 2008 was pre-operating allowance for funds used during construction in 2008. The 2009 results include a non-cash pre-tax charge of

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$16 million to reflect SESH’s decision to discontinue the use of guidance for accounting for regulated operations and the receipt of a one-time payment related to the construction of the pipeline and a reduction in estimated property taxes, of which our 50 percent share was $5 million. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Field Services

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

The following table provides summary data of our Field Services business segment for the three and nine months ended September 30, 2008 and 2009 (in millions, except throughput data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2009		2008		2009
Revenues	$	71	$	63	$	191	$	176
Expenses:
Natural gas		5		18		11		36
Operation and maintenance		19		17		48		54
Depreciation and amortization		3		4		9		11
Taxes other than income taxes		-		1		2		3
Total expenses		27		40		70		104
Operating Income	$	44	$	23	$	121	$	72

Gathering throughput (in Bcf) :		109		106		311		312

Three months ended September 30, 2009 compared to three months ended September 30, 2008

Our Field Services business segment reported operating income of $23 million for the three months ended September 30, 2009 compared to $44 million for the three months ended September 30, 2008. Operating income from new projects and core gathering services increased approximately $4 million for the three months ended September 30, 2009 when compared to the same period in 2008 primarily due to continued development in the shale plays. This increase was offset primarily by the effect of a decline in commodity prices from the significantly higher levels in 2008 of approximately $20 million. In addition, operating income decreased from the prior year quarter associated with gains from system imbalances ($3 million).

Equity Earnings. In addition, this business segment recorded equity income of $4 million and $2 million in the three months ended September 30, 2008 and 2009, respectively, from its 50 percent interest in a jointly-owned gas processing plant. The decrease is driven by a decrease in natural gas liquids prices. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Nine months ended September 30, 2009 compared to nine months ended September 30, 2008

Our Field Services business segment reported operating income of $72 million for the nine months ended September 30, 2009 compared to $121 million for the nine months ended September 30, 2008. Operating income from new projects and core gathering services increased approximately $16 million for the nine months ended September 30, 2009 when compared to the same period in 2008 primarily due to continued development in the shale plays. This increase was offset primarily by the effect of a decline in commodity prices of approximately $43 million from the significantly higher prices experienced in 2008. Operating income for the nine months ended September 30, 2009 also included higher costs associated with incremental facilities and increased pension costs ($5 million). The nine month period September 30, 2008 benefited from a one-time gain ($11 million) related to a settlement and contract buyout of one of our customers and a one-time gain ($6 million) related to the sale of assets.

Equity Earnings. In addition, this business segment recorded equity income of $12 million and $6 million in the nine months ended September 30, 2008 and 2009, respectively, from its 50 percent interest in a jointly-owned gas

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processing plant. The decrease is driven by a decrease in natural gas liquids prices. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

For information on other developments, factors and trends that may have an impact on our future earnings, please read “Risk Factors” in Item 1A of Part II of this Form 10-Q and “Management’s Narrative Analysis of Results of Operations — Certain Factors Affecting Future Earnings” in Item 7 of Part II of our 2008 Form 10-K and “Cautionary Statement Regarding Forward-Looking Information.”

LIQUIDITY AND CAPITAL RESOURCES

Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, tax payments and working capital needs. Our principal cash requirements for the remaining three months of 2009 are approximately $217 million of capital expenditures.

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

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

Prior to CenterPoint Energy’s distribution of its ownership in RRI Energy, Inc. (RRI) (formerly known as Reliant Energy, Inc. and Reliant Resources, Inc.) to its shareholders, we had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure us against obligations under the guaranties RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI has agreed to provide to us cash or letters of credit as security against our obligations under our remaining guaranties for demand charges under certain gas purchase and transportation agreements if and to the extent changes in market conditions expose us to a risk of loss on those guaranties. As of September 30, 2009, RRI was not required to provide security to us. If RRI should fail to perform the contractual obligations, we could have to honor our guarantee and, in such event, collateral provided as security may be insufficient to satisfy our obligations.

Credit and Receivables Facilities. On October 7, 2009, the size of CERC Corp.’s revolving credit facility was reduced from $950 million to $915 million through removal of Lehman as a lender. Prior to its removal, Lehman had a $35 million commitment to lend. All credit facility loans to CERC Corp. that were funded by Lehman were repaid in September 2009.

As of October 19, 2009, we had the following facilities (in millions):

Date Executed	Type of Facility	Size of Facility		Amount Utilized at October 19, 2009		Termination Date
June 29, 2007	Revolver	$	915	$	30	June 29, 2012
October 9, 2009	Receivables		150		—	October 8, 2010

CERC Corp.’s $915 million credit facility’s first drawn cost is the London Interbank Offered Rate (LIBOR) plus 45 basis points based on our current credit ratings. The facility contains a debt to total capitalization covenant. Under CERC Corp.’s credit facility, an additional utilization fee of 5 basis points applies to borrowings any time more than 50% of the facility is utilized. The spread to LIBOR and the utilization fee fluctuate based on CERC

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Corp.’s credit rating. Borrowings under this facility are subject to customary terms and conditions. However, there is no requirement that we make representations prior to borrowings as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under each of the credit facilities are subject to acceleration upon the occurrence of events of default that we consider customary.

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

CERC Corp.’s $915 million credit facility backstops a $915 million commercial paper program under which we began issuing commercial paper in February 2008. Our commercial paper is rated “P-3” by Moody’s Investors Service, Inc. (Moody’s), “A-3” by Standard & Poor’s Rating Services, a division of The McGraw Hill Companies (S&P), and “F2” by Fitch, Inc. (Fitch). As a result of the credit ratings on our commercial paper program, we do not expect to be able to rely on the sale of commercial paper to fund all of our short-term borrowing requirements. We cannot assure you that these ratings, or the credit ratings set forth below in “— Impact on Liquidity of a Downgrade in Credit Ratings,” will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing, the cost of such financings and the execution of our commercial strategies.

Securities Registered with the SEC. We have a shelf registration statement covering $500 million principal amount of senior debt securities.

Temporary Investments. As of October 19, 2009, we had no external temporary investments.

Money Pool. We participate in a money pool through which we and certain of our affiliates can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings by CenterPoint Energy under its revolving credit facility or the sale by CenterPoint Energy of its commercial paper. At October 19, 2009, we had borrowings of $272 million from the money pool. The money pool may not provide sufficient funds to meet our cash needs.

Impact on Liquidity of a Downgrade in Credit Ratings. As of October 19, 2009, Moody’s, S&P and Fitch had assigned the following credit ratings to our senior unsecured debt:

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

__________

(1)

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

(2)

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

(3)

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

A decline in credit ratings could increase borrowing costs under our $915 million revolving credit facility. If our credit ratings had been downgraded one notch by each of the three principal credit rating agencies from the ratings that existed at September 30, 2009, the impact on the borrowing costs under our bank credit facility would have been immaterial. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact our ability to complete capital market transactions. Additionally, a decline in credit ratings could increase our cash collateral requirements and reduce our earnings.

We and our subsidiaries purchase natural gas under supply agreements that contain an aggregate credit threshold of $100 million based on CERC Corp.’s S&P senior unsecured long-term debt rating of BBB. Upgrades and downgrades from this BBB rating will increase and decrease the aggregate credit threshold accordingly.

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CenterPoint Energy Services, Inc. (CES), our wholly owned subsidiary operating in our Competitive Natural Gas Sales and Services business segment, provides comprehensive natural gas sales and services primarily to commercial and industrial customers and electric and gas utilities throughout the central and eastern United States. In order to economically hedge its exposure to natural gas prices, CES uses derivatives with provisions standard for the industry, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the credit exposure that a counterparty has to CES at a particular time does not exceed that credit threshold, CES is not obligated to provide collateral. Mark-to-market exposure in excess of the credit threshold is routinely collateralized by CES. As of September 30, 2009, the amount posted as collateral aggregated approximately $140 million ($94 million of which is associated with price stabilization activities of our Natural Gas Distribution business segment). Should the credit ratings of CERC Corp. (as the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral up to the amount of its previously unsecured credit limit. We estimate that as of September 30, 2009, unsecured credit limits extended to CES by counterparties aggregate $241 million; however, utilized credit capacity was $73 million.

Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, we might need to provide cash or other collateral of as much as $180 million as of September 30, 2009. The amount of collateral will depend on seasonal variations in transportation levels.

Cross Defaults. Under CenterPoint Energy’s revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $50 million by us will cause a default. In addition, four outstanding series of CenterPoint Energy’s senior notes, aggregating $950 million in principal amount as of September 30, 2009, provide that a payment default by us in respect of, or an acceleration of, borrowed money and certain other specified types of obligations, in the aggregate principal amount of $50 million, will cause a default. A default by CenterPoint Energy would not trigger a default under our debt instruments or bank credit facilities.

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

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

•

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

•

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

•

increased costs related to the acquisition of natural gas;

•

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

•

various regulatory actions;

•

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

•

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

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•

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

•

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

•

the outcome of litigation brought by and against us;

•

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

•

various other risks identified in “Risk Factors” in Item 1A of Part II of this Form 10-Q.

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

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

NEW ACCOUNTING PRONOUNCEMENTS

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

Item 4T. CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2009 to provide assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.

There has been no change in our internal controls over financial reporting that occurred during the three months ended September 30, 2009 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

For a discussion of material legal and regulatory proceedings affecting us, please read Notes 4 and 11 to our Interim Condensed Financial Statements, each of which is incorporated herein by reference. See also “Business — Regulation” and “— Environmental Matters” in Item 1 and “Legal Proceedings” in Item 3 of our 2008 Form 10-K.

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Item 1A. RISK FACTORS

The following risk factors are provided to supplement and update the risk factors contained in the reports we file with the SEC, including the risk factors contained in Item 1A of Part I of our 2008 Form 10-K.

The following information about risks, along with any additional legal proceedings identified or referenced in Part II, Item 1 “Legal Proceedings” of this Form 10-Q and in “Legal Proceedings” in Item 3 of our 2008 Form 10-K, summarize the principal risk factors associated with our businesses.

Risk Factors Affecting Our Businesses

Rate regulation of our business may delay or deny our ability to earn a reasonable return and fully recover our costs.

Rates for our natural gas distribution business (Gas Operations) are regulated by certain municipalities and state commissions, and for our interstate pipelines by the Federal Energy Regulatory Commission, based on an analysis of our invested capital and our expenses in a test year. Thus, the rates that we are allowed to charge may not match our expenses at any given time. The regulatory process in which rates are determined may not always result in rates that will produce full recovery of our costs and enable us to earn a reasonable return on our invested capital.

Our businesses must compete with alternate energy sources, which could result in our marketing less natural gas, and our interstate pipelines and field services businesses must compete directly with others in the transportation, storage, gathering, treating and processing of natural gas, which could lead to lower prices and reduced volumes, either of which could have an adverse impact on our results of operations, financial condition and cash flows.

We compete primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other natural gas distributors and marketers also compete directly with us for natural gas sales to end-users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass our facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas marketed, sold or transported by us as a result of competition may have an adverse impact on our results of operations, financial condition and cash flows.

Our two interstate pipelines and our gathering systems compete with other interstate and intrastate pipelines and gathering systems in the transportation and storage of natural gas. The principal elements of competition are rates, terms of service, and flexibility and reliability of service. We also compete indirectly with other forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price. The actions of our competitors could lead to lower prices, which may have an adverse impact on our results of operations, financial condition and cash flows. Additionally, any reduction in the volume of natural gas transported or stored may have an adverse impact on our results of operations, financial condition and cash flows.

Our natural gas distribution and competitive natural gas sales and services businesses are subject to fluctuations in natural gas prices, which could affect the ability of our suppliers and customers to meet their obligations or otherwise adversely affect our liquidity and results of operations.

We are subject to risk associated with changes in the price of natural gas. Increases in natural gas prices might affect our ability to collect balances due from our customers and, for Gas Operations, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into our tariff rates. In addition, a sustained period of high natural gas prices could (i) apply downward demand pressure on natural gas consumption in the areas in which we operate thereby resulting in decreased sales volumes and revenues and (ii) increase the risk that our suppliers or customers fail or are unable to meet their obligations. An increase in natural gas prices would also increase our working capital requirements by increasing the investment that must be made in order to maintain natural gas inventory levels. Additionally, a decrease in natural gas prices could increase the amount of collateral that we must provide under our hedging arrangements.

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A decline in our credit rating could result in us having to provide collateral in order to purchase gas or under our shipping or hedging arrangements.

If our credit rating were to decline, we might be required to post cash collateral in order to purchase natural gas or under our shipping or hedging arrangements. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations, financial condition and cash flows could be adversely affected.

The revenues and results of operations of our interstate pipelines and field services businesses are subject to fluctuations in the supply and price of natural gas and natural gas liquids.

Our interstate pipelines and field services businesses largely rely on natural gas sourced in the various supply basins located in the Mid-continent region of the United States. The level of drilling and production activity in these regions is dependent on economic and business factors beyond our control. The primary factor affecting both the level of drilling activity and production volumes is natural gas pricing. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the regions served by our gathering and pipeline transportation systems and our natural gas treating and processing activities. A sustained decline could also lead producers to shut in production from their existing wells. Other factors that impact production decisions include the level of production costs relative to other available production, producers’ access to needed capital and the cost of that capital, the ability of producers to obtain necessary drilling and other governmental permits, access to drilling rigs and regulatory changes. Because of these factors, even if new natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves or to shut in production from existing reserves. To the extent the availability of this supply is substantially reduced, it could have an adverse effect on our results of operations, financial condition and cash flows.

Our revenues from these businesses are also affected by the prices of natural gas and natural gas liquids (NGL). NGL prices generally fluctuate on a basis that correlates to fluctuations in crude oil prices. In the past, the prices of natural gas and crude oil have been extremely volatile, and we expect this volatility to continue. The markets and prices for natural gas, NGLs and crude oil depend upon factors beyond our control. These factors include supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors.

Our revenues and results of operations are seasonal.

A substantial portion of our revenues is derived from natural gas sales and transportation. Thus, our revenues and results of operations are subject to seasonality, weather conditions and other changes in natural gas usage, with revenues being higher during the winter months.

The actual cost of pipelines under construction, future pipeline, gathering and treating systems and related compression facilities may be significantly higher than we had planned.

Our subsidiaries have been recently involved in significant pipeline construction projects and, depending on available opportunities, may, from time to time, be involved in additional significant pipeline construction and gathering and treating system projects in the future. The construction of new pipelines, gathering and treating systems and related compression facilities may require the expenditure of significant amounts of capital, which may exceed our estimates. These projects may not be completed at the planned cost, on schedule or at all. The construction of new pipeline, gathering, treating or compression facilities is subject to construction cost overruns due to labor costs, costs of equipment and materials such as steel and nickel, labor shortages or delays, weather delays, inflation or other factors, which could be material. In addition, the construction of these facilities is typically subject to the receipt of approvals and permits from various regulatory agencies. Those agencies may not approve the projects in a timely manner or may impose restrictions or conditions on the projects that could potentially prevent a project from proceeding, lengthen its expected completion schedule and/or increase its anticipated cost. As a result, there is the risk that the new facilities may not be able to achieve our expected investment return, which could adversely affect our financial condition, results of operations or cash flows.

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The states in which we provide regulated local gas distribution may, either through legislation or rules, adopt restrictions similar to or broader than those under the Public Utility Holding Company Act of 1935 regarding organization, financing and affiliate transactions that could have significant adverse impacts on our ability to operate.

The Public Utility Holding Company Act of 1935, to which CenterPoint Energy and its subsidiaries were subject prior to its repeal in the Energy Policy Act of 2005, provided a comprehensive regulatory structure governing the organization, capital structure, intracompany relationships and lines of business that could be pursued by registered holding companies and their member companies. Following repeal of that Act, some states in which we do business have sought to expand their own regulatory frameworks to give their regulatory authorities increased jurisdiction and scrutiny over similar aspects of the utilities that operate in their states. Some of these frameworks attempt to regulate financing activities, acquisitions and divestitures, and arrangements between the utilities and their affiliates, and to restrict the level of non-utility businesses that can be conducted within the holding company structure. Additionally they may impose record keeping, record access, employee training and reporting requirements related to affiliate transactions and reporting in the event of certain downgrading of the utility’s bond rating.

These regulatory frameworks could have adverse effects on our ability to operate our utility operations, to finance our business and to provide cost-effective utility service. In addition, if more than one state adopts restrictions over similar activities, it may be difficult for us to comply with competing regulatory requirements.

Risk Factors Associated with Our Consolidated Financial Condition

If we are unable to arrange future financings on acceptable terms, our ability to refinance existing indebtedness could be limited.

As of September 30, 2009, we had $3.1 billion of outstanding indebtedness on a consolidated basis. As of September 30, 2009, approximately $603 million principal amount of this debt is required to be paid through 2011 and an additional $239 million is money pool borrowings. Our future financing activities may be significantly affected by, among other things:

•	general economic and capital market conditions;

•	credit availability from financial institutions and other lenders;

•	investor confidence in us and the markets in which we operate;

•	maintenance of acceptable credit ratings;

•	market expectations regarding our future earnings and cash flows;

•	market perceptions of our and CenterPoint Energy's ability to access capital markets on reasonable terms;

•	our exposure to RRI in connection with its indemnification obligations arising in connection with its separation from us; and

•	provisions of relevant tax and securities laws.

Our current credit ratings are discussed in “Management’s Narrative Analysis of Results of Operations— Liquidity — Impact on Liquidity of a Downgrade in Credit Ratings” in Item 2 of Part I of this Form 10-Q. These credit ratings may not remain in effect for any given period of time and one or more of these ratings may 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. 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 access capital on acceptable terms.

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The creditworthiness and liquidity of our parent company and our affiliates could affect our creditworthiness and liquidity.

Our credit ratings and liquidity may be impacted by the creditworthiness and liquidity of our affiliates. As of September 30, 2009, CenterPoint Energy and its subsidiaries other than us have approximately $219 million principal amount of debt required to be paid through 2011. This amount excludes amounts related to capital leases, transition bonds and indexed debt securities obligations. If CenterPoint Energy were to experience a deterioration in its creditworthiness or liquidity, our creditworthiness and liquidity could be adversely affected. In addition, from time to time we and other affiliates invest or borrow funds in the money pool maintained by CenterPoint Energy. If CenterPoint Energy or the affiliates that borrow any funds that we might invest from time to time in the money pool were to experience a deterioration in their creditworthiness or liquidity, our creditworthiness, liquidity and the repayment of notes receivable from CenterPoint Energy and our affiliates under the money pool could be adversely impacted.

We are an indirect wholly owned subsidiary of CenterPoint Energy. CenterPoint Energy can exercise substantial control over our dividend policy and business and operations and could do so in a manner that is adverse to our interests.

We are managed by officers and employees of CenterPoint Energy. Our management will make determinations with respect to the following:

•	our payment of dividends;

•	decisions on our financings and our capital raising activities;

•	mergers or other business combinations; and

•	our acquisition or disposition of assets.

There are no contractual restrictions on our ability to pay dividends to CenterPoint Energy. Our management could decide to increase our dividends to CenterPoint Energy to support its cash needs. This could adversely affect our liquidity. However, under our credit facility and our receivables facility, our ability to pay dividends is restricted by a covenant that debt as a percentage of total capitalization may not exceed 65%.

The use of derivative contracts by us and our subsidiaries in the normal course of business could result in financial losses that could negatively impact our results of operations and those of our subsidiaries.

We and our subsidiaries use derivative instruments, such as swaps, options, futures and forwards, to manage our commodity, weather and financial market risks. We and our subsidiaries could recognize financial losses as a result of volatility in the market values of these contracts, or should a counterparty fail to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

We derive a substantial portion of our operating income from subsidiaries through which we hold a substantial portion of our assets.

We derive a substantial portion of our operating income from, and hold a substantial portion of our assets through, our subsidiaries. In general, these subsidiaries are separate and distinct legal entities and have no obligation to provide us with funds for our payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit our subsidiaries’ ability to make payments or other distributions to us, and our subsidiaries could agree to contractual restrictions on their ability to make distributions.

Our right to receive any assets of any subsidiary, and therefore the right of our creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary’s creditors, including trade creditors. In addition, even if we were a creditor of any subsidiary, our rights as a creditor would be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by us.

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Risks Common to Our Businesses and Other Risks

We are subject to operational and financial risks and liabilities arising from environmental laws and regulations.

Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of natural gas pipelines and distribution systems, and gas gathering and processing systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

•	restricting the way we can handle or dispose of wastes;

•	limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species;

•	requiring remedial action to mitigate pollution conditions caused by our operations, or attributable to former operations; and

•	enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.

In order to comply with these requirements, we may need to spend substantial amounts and devote other resources from time to time to:

•	construct or acquire new equipment;

•	acquire permits for facility operations;

•	modify or replace existing and proposed equipment; and

•	clean up or decommission waste disposal areas, fuel storage and management facilities and other locations and facilities.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial actions, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

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

We currently have general liability and property insurance in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows.

We and CenterPoint Energy could incur liabilities associated with businesses and assets that we have transferred to others.

Under some circumstances, we and CenterPoint Energy could incur liabilities associated with assets and businesses we and CenterPoint Energy no longer own.

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In connection with the organization and capitalization of RRI, RRI and its subsidiaries assumed liabilities associated with various assets and businesses Reliant Energy transferred to them. RRI also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, CenterPoint Energy and its subsidiaries, including us, with respect to liabilities associated with the transferred assets and businesses. These indemnity provisions were intended to place sole financial responsibility on RRI and its subsidiaries for all liabilities associated with the current and historical businesses and operations of RRI, regardless of the time those liabilities arose. If RRI were unable to satisfy a liability that has been so assumed in circumstances in which Reliant Energy and its subsidiaries were not released from the liability in connection with the transfer, we and, CenterPoint Energy could be responsible for satisfying the liability.

Prior to CenterPoint Energy's distribution of its ownership in RRI to its shareholders, we had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure us against obligations under the guaranties RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI has agreed to provide us cash or letters of credit as security against our obligations under its remaining guaranties if and to the extent changes in market conditions expose us to a risk of loss on those guaranties. As of September 30, 2009, RRI was not required to provide security to us. If RRI should fail to perform the contractual obligations, we could have to honor our guarantee and, in such event, collateral provided as security may be insufficient to satisfy our obligations.

Our potential exposure under the guaranties relates to payment of demand charges related to transportation contracts. The present value of the demand charges under these transportation contracts, which will be effective until 2018, was approximately $99 million as of September 30, 2009. RRI continues to meet its obligations under the contracts, and on the basis of market conditions, we and CenterPoint Energy have not required additional security. However, if RRI should fail to perform its obligations under the contracts or if RRI should fail to provide adequate security in the event market conditions change adversely, we would retain our exposure to the counterparty under the guaranty.

RRI’s unsecured debt ratings are currently below investment grade. If RRI were unable to meet its obligations, it would need to consider, among various options, restructuring under the bankruptcy laws, in which event RRI might not honor its indemnification obligations and claims by RRI’s creditors might be made against us as its former owner.

Reliant Energy and RRI are named as defendants in a number of lawsuits arising out of energy sales in California and other markets and financial reporting matters. Although these matters relate to the business and operations of RRI, claims against Reliant Energy have been made on grounds that include the effect of RRI’s financial results on Reliant Energy’s historical financial statements and liability of Reliant Energy as a controlling shareholder of RRI. We or CenterPoint Energy could incur liability if claims in one or more of these lawsuits were successfully asserted against us, CenterPoint Energy and indemnification from RRI were determined to be unavailable or if RRI were unable to satisfy indemnification obligations owed with respect to those claims.

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

The continued credit crisis and related turmoil in the global financial system may have an impact on our business, liquidity and our financial condition. Our ability to access the capital markets may be severely restricted at a time when we would like, or need, to access those markets, which could have an impact on our liquidity and flexibility to react to changing economic and business conditions. In addition, the cost of debt financing and the proceeds of equity financing may be materially adversely impacted by these market conditions. Defaults of lenders in our credit facility should they occur could adversely affect our liquidity. Capital market turmoil was also reflected in significant reductions in equity market valuations in 2008, which significantly reduced the value of assets of CenterPoint Energy's pension plan in which we participate. These reductions are expected to result in increased non-

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cash pension expense in 2009, which will impact 2009 results of operations and may impact liquidity if contributions are made to offset reduced asset values.

In addition to the credit and financial market issues, the national and local recessionary conditions may impact our business in a variety of ways. These include, among other things, reduced customer usage, increased customer default rates and wide swings in commodity prices.

Item 5. OTHER INFORMATION

Our ratio of earnings to fixed charges for the nine months ended September 30, 2008 and 2009 was 3.18 and 2.24, respectively. We do not believe that the ratios for these nine-month periods are necessarily indicative of the ratios for the twelve-month periods due to the seasonal nature of our business. The ratios were calculated pursuant to applicable rules of the Securities and Exchange Commission.

Item 6. EXHIBITS

The following exhibits are filed herewith:

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

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

Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1.1	–Certificate of Incorporation of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(1)
3.1.2	–Certificate of Merger merging former NorAm Energy Corp. with and into HI Merger, Inc. dated August 6, 1997	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(2)
3.1.3	–Certificate of Amendment changing the name to Reliant Energy Resources Corp.	Form 10-K for the year ended December 31, 1998	1-13265	3(a)(3)
3.1.4	–Certificate of Amendment changing the name to CenterPoint Energy Resources Corp.	Form 10-Q for the quarter ended June 30, 2003	1-13265	3(a)(4)
3.2	–Bylaws of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(b)
4.1	–$950,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CERC Corp., as Borrower, and the banks named therein	CERC Corp.’s Form 10-Q for the quarter ended June 30, 2007	1-13265	4.1
+12	–Computation of Ratios of Earnings to Fixed Charges
+31.1	–Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan

Table of Contents

Exhibit Number

Description

Report or Registration

Statement

SEC File or

Registration

Number

Exhibit

Reference

+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

Table of Contents

SIGNATURES

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

	CENTERPOINT ENERGY RESOURCES CORP.



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

Date: November 10, 2009

Table of Contents

Index to Exhibits

The following exhibits are filed herewith:

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

Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1.1	–Certificate of Incorporation of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(1)
3.1.2	–Certificate of Merger merging former NorAm Energy Corp. with and into HI Merger, Inc. dated August 6, 1997	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(2)
3.1.3	–Certificate of Amendment changing the name to Reliant Energy Resources Corp.	Form 10-K for the year ended December 31, 1998	1-13265	3(a)(3)
3.1.4	–Certificate of Amendment changing the name to CenterPoint Energy Resources Corp.	Form 10-Q for the quarter ended June 30, 2003	1-13265	3(a)(4)
3.2	–Bylaws of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(b)
4.1	–$950,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CERC Corp., as Borrower, and the banks named therein	CERC Corp.’s Form 10-Q for the quarter ended June 30, 2007	1-13265	4.1
+12	–Computation of Ratios of Earnings to Fixed Charges
+31.1	–Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan
+31.2	–Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock
+32.1	–Section 1350 Certification of David M. McClanahan
+32.2	–Section 1350 Certification of Gary L. Whitlock

CENTERPOINT ENERGY RESOURCES CORP - FORM 10-Q - November 10, 2009

Attached files

CENTERPOINT ENERGY RESOURCES CORP Reports