Centerpoint Energy Resources 10Q 2010 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

	FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2010
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	FOR THE TRANSITION PERIOD FROM TO

Commission file number 1-13265

CENTERPOINT ENERGY RESOURCES CORP.

(Exact name of registrant as specified in its charter)

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

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

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

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

Indicate by check mark whether the registrant 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 o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See 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 o No þ

As of July 26, 2010, all 1,000 shares of CenterPoint Energy Resources Corp. common stock were held by Utility Holding, LLC, a wholly owned subsidiary of CenterPoint Energy, Inc.

CENTERPOINT ENERGY RESOURCES CORP.

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2010

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	1

	Condensed Statements of Consolidated Income
	Three and Six Months Ended June 30, 2009 and 2010 (unaudited)	1

	Condensed Consolidated Balance Sheets
	December 31, 2009 and June 30, 2010 (unaudited)	2

	Condensed Statements of Consolidated Cash Flows
	Six Months Ended June 30, 2009 and 2010 (unaudited)	4

	Notes to Unaudited Condensed Consolidated Financial Statements	5

Item 2.	Management’s Narrative Analysis of Results of Operations	20

Item 4.	Controls and Procedures	30

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	30

Item 1A.	Risk Factors	30

Item 5.	Other Information	37

Item 6.	Exhibits	38

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

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

•

state and federal legislative and regulatory actions or developments relating to the environment, including those related to global climate change;

•

other state and federal legislative and regulatory actions or developments affecting various aspects of our business, including, among others, energy deregulation or re-regulation, health care reform and financial reform;

•

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

•

the timing and outcome of any audits, disputes or other proceedings relating to taxes;

•

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

•

industrial, commercial and residential growth in our service territory and changes in market demand, including the effects of energy efficiency measures, and demographic patterns;

•

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

•

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

•

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

•

weather variations and other natural phenomena;

•

the impact of unplanned facility outages;

•

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;

•

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

•

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

•

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

•

other factors we discuss in “Risk Factors” in Item 1A of Part 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

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 June 30,						Six Months Ended June 30,
	2009			2010			2009			2010

Revenues	$	1,116		$	1,191		$	3,467		$	3,729

Expenses:
Natural gas		710			778			2,499			2,713
Operation and maintenance		223			214			456			446
Depreciation and amortization		57			63			114			123
Taxes other than income taxes		37			35			95			98
Total		1,027			1,090			3,164			3,380

Operating Income		89			101			303			349

Other Income (Expense): Interest and other finance charges		(53	)		(52	)		(107	)		(103	)
Equity in earnings of unconsolidated affiliates		11			7			11			12
Other, net		2			—			3			—
Total		(40	)		(45	)		(93	)		(91	)

Income Before Income Taxes		49			56			210			258
Income tax expense		(15	)		(23	)		(81	)		(119	)
Net Income	$	34		$	33		$	129		$	139

See Notes to the Interim Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

(Unaudited)

ASSETS

	December 31, 2009		June 30, 2010
Current Assets:
Cash and cash equivalents	$	1	$	1
Accounts and notes receivable, net		593		446
Accrued unbilled revenue		421		88
Accounts and notes receivable – affiliated companies		13		16
Materials and supplies		69		88
Natural gas inventory		189		146
Non-trading derivative assets		39		46
Taxes receivable		47		—
Deferred tax asset		16		60
Prepaid expenses and other current assets		144		166
Total current assets		1,532		1,057

Property, Plant and Equipment:
Property, plant and equipment		6,987		7,460
Less accumulated depreciation and amortization		1,112		1,218
Property, plant and equipment, net		5,875		6,242

Other Assets:
Goodwill		1,696		1,696
Non-trading derivative assets		15		17
Investment in unconsolidated affiliates		463		479
Other		203		178
Total other assets		2,377		2,370

Total Assets	$	9,784	$	9,669

See Notes to the Interim Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED BALANCE SHEETS — (Continued)

(Millions of Dollars)

(Unaudited)

LIABILITIES AND STOCKHOLDER’S EQUITY

	December 31, 2009			June 30, 2010
Current Liabilities:
Short-term borrowings	$	55		$	32
Current portion of long-term debt		44			550
Accounts payable		563			334
Accounts and notes payable — affiliated companies		472			374
Taxes accrued		67			118
Interest accrued		52			51
Customer deposits		70			71
Non-trading derivative liabilities		51			63
Other		282			303
Total current liabilities		1,656			1,896

Other Liabilities:
Accumulated deferred income taxes, net		1,080			1,129
Non-trading derivative liabilities		42			30
Benefit obligations		113			109
Regulatory liabilities		539			563
Other		135			134
Total other liabilities		1,909			1,965

Long-term Debt		2,742			2,192

Commitments and Contingencies (Note 11)

Stockholder’s Equity:
Common stock		—			—
Paid-in capital		2,416			2,416
Retained earnings		1,065			1,204
Accumulated other comprehensive loss		(4	)		(4	)
Total stockholder’s equity		3,477			3,616

Total Liabilities and Stockholder’s Equity	$	9,784		$	9,669

See Notes to the Interim Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Millions of Dollars)

(Unaudited)

	Six Months Ended June 30,
	2009			2010
Cash Flows from Operating Activities:
Net income	$	129		$	139
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		114			123
Amortization of deferred financing costs		5			4
Deferred income taxes		76			(1	)
Write-down of natural gas inventory		6			—
Equity in earnings of unconsolidated affiliates, net of distributions		(8	)		6
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net		684			434
Accounts receivable/payable, affiliates		9			(12	)
Inventory		330			24
Taxes receivable		(35	)		47
Accounts payable		(424	)		(236	)
Fuel cost over (under) recovery		(34	)		93
Interest and taxes accrued		(43	)		50
Non-trading derivatives, net		20			3
Margin deposits, net		39			(18	)
Other current assets		15			(6	)
Other current liabilities		(7	)		(14	)
Other assets		2			1
Other liabilities		8			(8	)
Other, net		—			—
Net cash provided by operating activities		886			629

Cash Flows from Investing Activities:
Capital expenditures		(272	)		(449	)
Investment in unconsolidated affiliates		1			(22	)
Other, net		(3	)		(1	)
Net cash used in investing activities		(274	)		(472	)

Cash Flows from Financing Activities:
Decrease in short-term borrowings, net		(78	)		(23	)
Revolving credit facility, net		(526	)		—
Payments of long-term debt		(6	)		(45	)
Decrease in notes payable to affiliates		—			(89	)
Other, net		1			—
Net cash used in financing activities		(609	)		(157	)

Net Increase in Cash and Cash Equivalents		3			—
Cash and Cash Equivalents at Beginning of Period		1			1
Cash and Cash Equivalents at End of Period	$	4		$	1

Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	104		$	97
Income taxes		64			15
Non-cash transactions:
Accounts payable related to capital expenditures		36			61

See Notes to the Interim Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1)	Background and Basis of Presentation

General. Included in this Quarterly Report on Form 10-Q (Form 10-Q) of CenterPoint Energy Resources Corp. (CERC Corp.) are the condensed consolidated interim financial statements and notes (Interim Condensed Financial Statements) of CenterPoint Energy Resources Corp. and its subsidiaries (collectively, CERC). The Interim Condensed Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the Annual Report on Form 10-K of CERC Corp. for the year ended December 31, 2009 (CERC Corp. Form 10-K).

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

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

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

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

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

(2)	New Accounting Pronouncements

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

In January 2010, the FASB issued new accounting guidance to require additional fair value related disclosures including transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. It also clarifies existing fair value disclosure guidance about the level of disaggregation and about inputs and valuation techniques. This new guidance was effective for the first reporting period beginning after December 15, 2009 except for the requirement to separately disclose purchases, sales, issuances and settlements relating to Level 3 measurements, which is effective for the first reporting period beginning after December 15, 2010. CERC's adoption of this new guidance did not have a material impact on its financial position, results of operations or cash flows . See Note 6 for the required disclosures. CERC expects that the adoption of the Level 3 related gross disclosure requirement, which is effective in 2011, will not have a material impact on its financial position, results of operations or cash flows.

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 June 30,				Six Months Ended June 30,
	2009		2010		2009		2010
	(in millions)
Interest cost	$	2	$	1	$	4	$	3
Amortization of prior service cost		1		1		1		1
Net periodic cost	$	3	$	2	$	5	$	4

CERC expects to contribute approximately $15 million to CenterPoint Energy’s postretirement benefit plan in 2010, of which $4 million and $8 million, respectively, was contributed during the three and six months ended June 30, 2010.

(4)	Regulatory Matters

Texas. In March 2008, the natural gas distribution business of CERC (Gas Operations) filed a request to change its rates with the Railroad Commission of Texas (Railroad Commission) and the 47 cities in its Texas Coast service territory, an area consisting of approximately 230,000 customers in cities and communities on the outskirts of Houston. In 2008, the Railroad Commission approved the implementation of rates increasing annual revenues by approximately $3.5 million. The implemented rates were contested by a coalition of nine cities in an appeal to the 353rd District Court in Travis County, Texas. In January 2010, that court reversed the Railroad Commission’s order in part and remanded the matter to the Railroad Commission. In its final judgment, the cou rt ruled that the Railroad Commission lacked authority to impose the approved cost of service adjustment mechanism in both those nine cities and in those areas in which the Railroad Commission has original jurisdiction. The Railroad Commission and Gas Operations have appealed the court’s ruling on the cost of service adjustment mechanism to the 3rd Court of Appeals at Austin, Texas. 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.

In July 2009, Gas Operations filed a request to change its rates with the Railroad Commission and the 29 cities in its Houston service territory, consisting of approximately 940,000 customers in and around Houston. The request sought to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Houston service territory. As finally submitted to the Railroad Commission and the cities, the proposed new rates would have resulted in an overall increase in annual revenue of $20.4 million, excluding carrying costs of approximately $2 million on its gas inventory. In January 2010, Gas Operations withdrew its request for an annual cost of service adjustment mechanism due to the uncertainty caused by the court’s ruling in the above-mentioned Texas Coast appeal. In February 2010, the Railroad Commission issued its decision authorizing a revenue increase of $5.1 million annually, reflecting reduced depreciation rates as well as adjustments to pension and benefits, accumulated deferred income taxes and other items. The Railroad Commission also approved a surcharge of $0.9 million per year to recover Hurricane Ike costs over three years. These rates went into effect in March 2010. Gas Operations and other parties are seeking judicial review of the Railroad Commission's decision in the 261st district court in Travis County, Texas.

Minnesota. In November 2008, Gas Operations filed a request with the Minnesota Public Utilities Commission (MPUC) to increase its rates for utility distribution service by $59.8 million annually. In addition, Gas Operations sought an adjustment mechanism that would annually adjust rates to reflect changes in use per customer. In December 2008, the MPUC accepted the case and approved an interim rate increase of $51.2 million, which became effective on January 2, 2009, subject to refund. In January 2010, the MPUC issued its decision authorizing a revenue increase of $40.8 million per year, with an overall rate of return of 8.09% (10.24% return on equity). The MPUC also authorized Gas Operations to implement a pilot program for residential and small volume commercial customers that is intended to decouple gas revenues from customers’ natural gas usage. In July 2010, Gas

Operations implemented the revised rates approved by the MPUC. The difference between the amounts approved by the MPUC and amounts collected, $15.9 million as of June 30, 2010, is recorded in other current liabilities and will be refunded to customers in 2010.

(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.

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

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

(a) Non-Trading Activities

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

During the three months ended June 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 $40 million, resulting in a net unrealized gain of $3 million. During the three months ended June 30, 2010, CERC recorded decreased natural gas revenues from unrealized net losses of $13 million and decreased natural gas expense from unrealized net gains of $5 million, resulting in a net unrealized loss of $8 million. During the six months ended June 30, 2009, CERC recorded decreased natural gas revenues from unrealized net losses of $34 million and decreased natural gas expense from unrealized net gains of $18 million, resulting in a net unrealized loss of $16 m illion. During the six months ended June 30, 2010, CERC recorded increased natural gas revenues from unrealized net gains of $17 million and increased natural gas expense from unrealized net losses of $22 million, resulting in a net unrealized loss of $5 million.

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

CERC enters into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the winter heating season. The swaps are based on ten-year normal weather. During the three and six months ended June 30, 2009, CERC recognized losses of $-0- and $3 million, respectively, related to these swaps. During the three and six months ended June 30, 2010, CERC recognized gains of $2 million and losses of $5 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 tables provide a balance sheet overview of CERC’s Derivative Assets and Liabilities as of December 31, 2009 and June 30, 2010, while the latter tables provide a breakdown of the related income statement impact for the three and six months ended June 30, 2009 and 2010.

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

_________

(1)

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

(2)

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

(3)

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

Fair Value of Derivative Instruments
	June 30, 2010
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value (2) (3)		Derivative Liabilities Fair Value (2) (3)
		(in millions)
Natural gas contracts (1)	Current Assets	$	48	$	(2	)
Natural gas contracts (1)	Other Assets		17		—
Natural gas contracts (1)	Current Liabilities		17		(156	)
Natural gas contracts (1)	Other Liabilities		1		(67	)
Total		$	83	$	(225	)

_________

(1)

(2)

The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 741 Bcf or a net 158 Bcf long position. Of the net long position, basis swaps constitute 86 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment comprise 40 Bcf.

(3)

The net of total non-trading derivative assets and liabilities is a $30 million liability as shown on CERC’s Condensed Consolidated Balance Sheets, and is comprised of the natural gas contracts derivative assets and liabilities separately shown above offset by collateral netting of $112 million.

For CERC’s price stabilization activities of the Natural Gas Distribution business segment, the settled costs of derivatives are ultimately recovered through purchased gas adjustments. Accordingly, the net unrealized gains and losses associated with these contracts are recorded as net regulatory assets/liabilities. Realized and unrealized gains and losses on other derivatives are recognized in the Condensed Statements of Consolidated Income as revenue for retail sales

derivative contracts and as natural gas expense for natural gas derivatives and non-retail related physical gas derivatives.

Income Statement Impact of Derivative Activity
		Three Months Ended June 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2009			2010
		(in millions)
Natural gas contracts	Gains (Losses) in Revenue	$	7		$	5
Natural gas contracts (1)	Gains (Losses) in Expense: Natural Gas		(43	)		(31	)
Total		$	(36	)	$	(26	)

_________

(1)

The Gains (Losses) in Expense: Natural Gas includes $(39) million and $(25) million of costs in 2009 and 2010, respectively, associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered/refunded through purchased gas adjustments.

Income Statement Impact of Derivative Activity
		Six Months Ended June 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2009			2010
		(in millions)
Natural gas contracts	Gains (Losses) in Revenue	$	84		$	49
Natural gas contracts (1)	Gains (Losses) in Expense: Natural Gas		(192	)		(92	)
Total		$	(108	)	$	(43	)

_________

(1)

The Gains (Losses) in Expense: Natural Gas includes $(117) million and $(50) million of costs in 2009 and 2010, respectively, associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered/refunded through purchased gas adjustments.

CERC enters into financial derivative contracts containing material adverse change provisions. These provisions require CERC to post additional collateral if the Standard & Poor’s Rating Services or Moody’s Investors Service, Inc. credit rating of CERC is downgraded. The total fair value of the derivative instruments that contain credit risk contingent features that are in a net liability position at December 31, 2009 and June 30, 2010 was $140 million and $144 million, respectively. The aggregate fair value of assets that are already posted as collateral was $65 million and $59 million, respectively, at December 31, 2009 and June 30, 2010. If all derivative contracts (in a net liability position) containing credit risk contingent features w ere triggered at December 31, 2009 and June 30, 2010, $75 million and $84 million, respectively, of additional assets would be required to be posted as collateral.

(6)	Fair Value Measurements

Assets and liabilities are recorded at fair value in the Condensed Consolidated Balance Sheets and are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined in this guidance and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities, are as follows:

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

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

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. In certain cases, the inputs used to measure fair value may fall into

different levels of the fair value hierarchy. In such cases, the level in the fair value hierarchy within which the fair value measurement in its entirety falls has been determined based on the lowest level input that is significant to the fair value measurement in its entirety. Unobservable inputs reflect CERC’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. CERC develops these inputs based on the best information available, including CERC’s own data. A market approach is utilized to value CERC’s Level 3 assets or liabilities. CERC’s Level 3 derivative instruments primarily consist of options that are not traded on recognized exchanges and are valued using option pricing models.

CERC determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes any transfers at the end of the reporting period. For the quarter ended June 30, 2010, there were no significant transfers between levels.

The following tables present information about CERC’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of December 31, 2009 and June 30, 2010, and indicate the fair value hierarchy of the valuation techniques utilized by CERC to determine such fair value.

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

(1)

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

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of June 30, 2010
	(in millions)
Assets
Corporate equities	$	1	$	—	$	—	$	—		$	1
Investments in money market funds		11		—		—		—			11
Derivative assets		1		75		7		(20	)		63
Total assets	$	13	$	75	$	7	$	(20	)	$	75
Liabilities
Derivative liabilities	$	13	$	210	$	2	$	(132	)	$	93
Total liabilities	$	13	$	210	$	2	$	(132	)	$	93

(1)

Amounts represent the impact of legally enforceable master netting agreements that allow CERC to settle positive and negative positions and also include cash collateral of $112 million posted with the same counterparties.

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

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	Three Months Ended June 30,
	2009			2010
	(in millions)
Beginning balance	$	(26	)	$	4
Total unrealized gains or (losses):
Included in earnings		1			—
Included in regulatory assets		1			—
Total purchases, sales, other settlements, net:
Included in earnings		—			1
Included in regulatory assets		7			—
Ending balance	$	(17	)	$	5
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	$	1		$	1

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	Six Months Ended June 30,
	2009			2010
	(in millions)
Beginning balance	$	(58	)	$	(6	)
Total unrealized gains or (losses):
Included in earnings		(2	)		2
Included in regulatory assets		(16	)		(1	)
Total purchases, sales, other settlements, net:
Included in earnings		2			1
Included in regulatory assets		57			9
Ending balance	$	(17	)	$	5
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	(1	)	$	3

(7)

Goodwill

Goodwill by reportable business segment as of both December 31, 2009 and June 30, 2010 is as follows (in millions):

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

(8)	Comprehensive Income

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2009		2010		2009		2010
	(in millions)
Net income	$	34	$	33	$	129	$	139
Other comprehensive income:
Adjustment to pension and other postretirement plans (net of tax of $-0- and $-0-)		1		—		1		—
Total		1		—		1		—
Comprehensive income	$	35	$	33	$	130	$	139

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

	December 31, 2009			June 30, 2010
	(in millions)
Adjustment to pension and other postretirement plans	$	(4	)	$	(4	)
Total accumulated other comprehensive loss	$	(4	)	$	(4	)

(9)	Related Party Transactions

CERC participates in a “money pool” through which it can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. CERC had money pool borrowings of $432 million and $342 million at December 31, 2009 and June 30, 2010, respectively, which are included in accounts and notes payable—affiliated companies in the Condensed Consolidated Balance Sheets.

For both the three and six months ended June 30, 2009 and 2010, CERC had net interest expense related to affiliate borrowings of less than $1 million.

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 $39 million and $37 million for the three months ended June 30, 2009 and 2010, respectively, and $76 million and $74 million for the six months ended June 30, 2009 and 2010, respectively, and are included primarily in operation and mai ntenance expenses.

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

(a) Short-term Borrowings

Receivables Facility. On October 9, 2009, CERC amended its receivables facility to extend the termination date to October 8, 2010. Availability under CERC’s 364-day receivables facility ranges from $150 million to $375 million, reflecting seasonal changes in receivables balances. As of December 31, 2009 and June 30, 2010, the facility size was $150 million and $300 million, respectively. As of both December 31, 2009 and June 30, 2010, there were no advances under the receivables facility.

Inventory Financing. In October 2009, Gas Operations entered into asset management agreements associated with its utility distribution service in Arkansas, north Louisiana and Oklahoma. Pursuant to the provisions of the agreements, Gas Operations sells natural gas and agrees to repurchase an equivalent amount of natural gas during the winter heating seasons at the same cost, plus a financing charge. These transactions are accounted for as a

financing and they had an associated principal obligation of $55 million and $32 million as of December 31, 2009 and June 30, 2010, respectively.

Also in October 2009, Gas Operations entered into asset management agreements associated with its utility distribution service in south Louisiana, Mississippi and Texas. In connection with these asset management agreements, Gas Operations exchanged natural gas in storage for the right to receive an equivalent amount of natural gas during the 2009-2010 winter heating season. Although title to the natural gas in storage at inception of the contract was transferred to the third party, the natural gas continued to be accounted for as inventory due to the right to receive an equivalent amount of natural gas during the winter heating season. As of December 31, 2009 and June 30, 2010, CERC’s Condensed Consolidated Balance Sheets reflect $10 million and $-0-, respectively, in inventory related to these agreements.

(b) Long-term Debt

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

Revolving Credit Facility. As of both December 31, 2009 and June 30, 2010, CERC Corp. had no outstanding borrowings under its $915 million credit facility. There was no commercial paper outstanding that would have been backstopped by CERC Corp.’s credit facility as of December 31, 2009 and June 30, 2010. CERC Corp. was in compliance with all debt covenants as of June 30, 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 CERC Corp.’s current credit ratings. The facility contains a debt to total capitalization covenant.

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

(11)	Commitments and Contingencies

(a) Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to CERC’s Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in CERC’s Condensed Consolidated Balance Sheets as of December 31, 2009 and June 30, 2010 as these contracts meet the exception to be classified as "normal purchases contracts" or do not meet the definition of a derivative. Natural gas supply commitments also include natural gas transportation contracts that do not meet the definition of a derivative. As of June 30, 2010, minimum payment obligations for natural gas supply commitments are approximately $262 million for the remaining six months in 20 10, $501 million in 2011, $407 million in 2012, $346 million in 2013, $255 million in 2014 and $579 million after 2014.

(b) Capital Commitments

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

In connection with the agreements, CEFS commenced gathering and treating services utilizing the acquired facilities. CEFS is expanding the acquired facilities in order to gather and treat up to 700 million cubic feet (MMcf) per day of natural gas and expects to place the majority of those facilities in service in the third quarter of 2010 with well connects being the only activity remaining. CEFS estimates that the purchase of existing facilities and construction to gather 700 MMcf per day will cost up to $325 million. As of June 30, 2010, approximately $286 million has been spent on the original project scope, including the purchase of existing facilities.

Under the agreements, Encana or Shell can elect to require CEFS to further expand the facilities in order to gather and treat a total volume of up to 1 Bcf per day, and in March 2010, Encana and Shell exercised initial expansion elections to increase gathering capacity by 200 MMcf per day to 900 MMcf. Total capital expenditures for this expansion are estimated to be approximately $60 million, and the increased capacity is expected to be in service by the first quarter of 2011. In connection with the expansion, Encana and Shell each made incremental volume commitments for the capacity expansion.

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

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

CEFS has integrated the acquired facilities with CEFS’s Magnolia Gathering System, allowing CEFS to commence gathering and treating services immediately for up to 150 MMcf per day of natural gas. Under the terms of the agreements, CEFS will expand the acquired facilities to gather and treat up to 600 MMcf per day of natural gas. Each of the agreements includes volume commitments and dedicated acreage for which CEFS has exclusive rights to gather Shell’s and Encana’s natural gas production.

CEFS estimates that the capital cost to purchase the existing facilities and construct new facilities for the Olympia Gathering System to gather 600 MMcf per day will be as much as $400 million. As of June 30, 2010, approximately $141 million has been spent on this project, including the purchase of existing facilities. If Encana and Shell elect, CEFS will expand the project to gather and treat additional future volumes of up to 520 MMcf per day, for a total Olympia Gathering System capacity of up to 1.1 Bcf per day. CEFS estimates that the incremental expansion to 1.1 Bcf per day would cost as much as an additional $200 million. Encana and Shell would provide incremental volume commitments in connection with expansions of the Olympia Gathering System.

Legal Matters

Gas Market Manipulation Cases. CenterPoint Energy or its predecessor, Reliant Energy, Incorporated (Reliant Energy), and certain of their former subsidiaries are named as defendants in several lawsuits described below. Under a master separation agreement between CenterPoint Energy and RRI (formerly known as Reliant Resources, Inc. and Reliant Energy, Inc.), CenterPoint Energy and its subsidiaries are entitled to be indemnified by RRI for any losses, including attorneys’ fees and other costs, arising out of these lawsuits. Pursuant to the indemnification obligation, RRI is defending CenterPoint Energy and its subsidiaries to the extent named in these lawsuits. A large number of lawsuits were filed against numerous gas market participan ts in a number of federal and western state courts in connection with the operation of the natural gas markets in 2000-2002. CenterPoint Energy’s former affiliate, RRI, was a participant in gas trading in the California and Western markets. These lawsuits, many of which have been filed as class actions, allege violations of state and federal antitrust laws. Plaintiffs in these lawsuits are seeking a variety of forms of relief, including, among others, recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages, full consideration damages and attorneys’ fees. CenterPoint Energy and/or Reliant Energy were named in approximately 30 of these lawsuits, which were instituted between 2003 and 2009. CenterPoint Energy and its affiliates have been released or dismissed from all but two of such cases. CenterPoint Energy Services, Inc. (CES), a subsidiary of CERC Corp., is a defendant in a case now pending in federal c ourt in Nevada alleging a conspiracy to inflate Wisconsin natural gas prices in 2000-

2002. Additionally, CenterPoint Energy was a defendant in a lawsuit filed in state court in Nevada that was dismissed in 2007, but in March 2010 the plaintiffs appealed the dismissal to the Nevada Supreme Court. CERC believes that neither CenterPoint Energy 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.

In May 2009, RRI sold its Texas retail business to NRG Retail LLC, a subsidiary of NRG Energy, Inc. In connection with the sale, RRI changed its name to RRI Energy, Inc. In April 2010, RRI announced its plan to merge with Mirant Corporation in an all-stock transaction. Neither the sale of the retail business nor the merger with Mirant Corporation, if ultimately finalized, alters RRI’s contractual obligations to indemnify CenterPoint Energy and its subsidiaries for certain liabilities, including their indemnification regarding certain litigation, nor does it affect the terms of existing guaranty arrangements for certain RRI gas transportation contracts discussed below under Guaranties.

Natural Gas Measurement Lawsuits. CERC Corp. and certain of its subsidiaries are defendants in two mismeasurement lawsuits brought against approximately 245 pipeline companies and their affiliates pending in state court in Stevens County, Kansas. In one case (originally filed in May 1999 and amended four times), the plaintiffs purport to represent a class of royalty owners who allege that the defendants have engaged in systematic mismeasurement of the volume of natural gas for more than 25 years. The plaintiffs amended their petition in this suit in July 2003 in response to an order from the judge denying certification of the plaintiffs’ alleged class. In the amendment, the plaintiffs dismissed their claims against certain defendants (including two CE RC Corp. subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the British thermal unit (Btu) content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a putative class of royalty owners in which they assert their claims that the defendants have engaged in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. In September 2009, the district court in Stevens County, Kansas, denied plaintiffs’ request for class certification of their case and, in March 2010, denied the plaintiffs’ request for reconsideration of that order.

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

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 June 30, 2010, CERC had accrued $14 million for remediation of these Minnesota sites and the estimated range of possible remediation costs for these sites was $4 million to $35 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. CERC has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. In January 2010, as part of its Minnesota rate case decision, the MPUC eliminated the environmental expense tracker mechani sm and ordered amounts previously collected from ratepayers and related carrying costs refunded to customers in 2010. As of June 30, 2010, the amount to be refunded from the environmental expense tracker account was $8.3 million. The MPUC provided for the inclusion in rates of approximately $285,000 annually to fund normal on-going remediation costs. CERC was not required to refund to customers the amount collected from insurance companies, $5.0 million at June 30, 2010, to be used to mitigate future environmental costs. The MPUC further gave assurance that any reasonable and prudent environmental clean-up costs CERC incurs in the future will be rate-recoverable under normal regulatory principles and procedures. This provision had no impact on earnings.

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

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

Groundwater Contamination Litigation. Predecessor entities of CERC, along with several other entities, are defendants in litigation, St. Michel Plantation, LLC, et al, v. White, et al., pending in civil district court in Orleans Parish, Louisiana. In the lawsuit, the plaintiffs allege that their property in Terrebonne Parish, Louisiana suffered salt water contamination as a result of oil and gas drilling activities conducted by the defendants. Although a predecessor of CERC held an interest in two oil and gas leases on a portion of the property at issue, neither it nor any other CERC entities drilled or conducted other oil and gas operations on those leases. In January 2009, CERC and the plaint iffs reached agreement on the terms of a settlement that, if ultimately approved by the Louisiana Department of Natural Resources, is expected to resolve this litigation. CERC does not expect the outcome of this litigation to have a material adverse impact on its financial condition, results of operations or cash flows.

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

Other Proceedings

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

(d) Guaranties

Prior to CenterPoint Energy’s distribution of its ownership in RRI to its shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure CERC against obligations under the guaranties RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI has agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guaranties for demand charges under certain gas transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guaranties. The present value of the demand charges under these transportation contracts, which will be in effect until 2018, w as approximately $89 million as of June 30, 2010. As of June 30, 2010, RRI was not required to provide security to CERC. If RRI should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, collateral provided as security may be insufficient to satisfy CERC’s obligations.

(12)	Income Taxes

During the three and six months ended June 30, 2009, the effective tax rate was 30% and 39%, respectively. During the three and six months ended June 30, 2010, the effective tax rate was 41% and 46%, respectively. The comparability of the effective tax rate for the three months ended June 30, 2009 and 2010 is primarily affected by a $3 million tax benefit related to an adjustment to deferred state tax liabilities in 2009. The comparability of the effective tax rate for the six months ended June 30, 2009 and 2010 is primarily affected by a non-cash, $19 million increase in the 2010 income tax expense as a result of a change in tax law upon the enactment in March 2010 of the Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act of 2010.

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

The following table summarizes CERC’s unrecognized tax benefits at December 31, 2009 and June 30, 2010:

	December 31, 2009			June 30, 2010
	(in millions)
Unrecognized tax benefits	$	6		$	4
Portion of unrecognized tax benefits that, if recognized, would reduce the effective income tax rate		—			—
Interest accrued on unrecognized tax benefits		(5	)		(5	)

It is reasonably possible that the total amount of unrecognized tax benefits could decrease by as much as $2 million over the next 12 months primarily as a result of the anticipated resolution of CenterPoint Energy’s administrative appeal associated with an Internal Revenue Service (IRS) examination described in the following paragraph. It is also reasonably possible that the total amount of unrecognized tax benefits could increase by as much as $17 million primarily as a result of the acceptance by the IRS of a refund claim related to the timing of a deduction for debt issuance costs.

On July 1, 2010, the IRS issued a report outlining proposed adjustments with respect to its examination of CenterPoint Energy’s 2006 and 2007 federal income tax returns of which CERC is a member. The most significant adjustment proposed by the IRS that is associated with CERC relates to the capitalization of certain direct and indirect expenses totaling approximately $4 million into inventory. CenterPoint Energy has filed an administrative appeal with the IRS Appeals Office but the proposed inventory adjustment was not contested. CERC has considered the adjustment’s effects in its accrual for uncertain income tax positions as of June 30, 2010. Additionally, the capitalization of expenses into inventory is a temporary difference and therefore, any increase or decrease in the balance of unrecognized tax benefits related thereto would not affect the effective tax rate.

(13)	Estimated Fair Value of Financial Instruments

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

	December 31, 2009				June 30, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	2,786	$	2,969	$	2,742	$	2,982

(14)	Reportable Business Segments

Because CERC Corp. 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 in the CERC Corp. Form 10-K. CERC uses operating income as the measure of profit or loss for its business segments.

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

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

	For the Three Months Ended June 30, 2009
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)
Natural Gas Distribution	$	516	$	2		$	2
Competitive Natural Gas Sales and Services		430		2			6
Interstate Pipelines		119		36			61
Field Services		51		5			23
Other Operations		—		—			(3	)
Eliminations		—		(45	)		—
Consolidated	$	1,116	$	—		$	89

	For the Three Months Ended June 30, 2010
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)
Natural Gas Distribution	$	462	$	3		$	10
Competitive Natural Gas Sales and Services		550		10			(6	)
Interstate Pipelines		113		35			67
Field Services		66		14			31
Other Operations		—		—			(1	)
Eliminations		—		(62	)		—
Consolidated	$	1,191	$	—		$	101

	For the Six Months Ended June 30, 2009
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2009
Natural Gas Distribution	$	1,934	$	5		$	120		$	4,535
Competitive Natural Gas Sales and Services		1,190		7			8			1,176
Interstate Pipelines		236		72			130			3,484
Field Services		107		6			49			1,045
Other Operations		—		—			(4	)		800
Eliminations		—		(90	)		—			(1,256	)
Consolidated	$	3,467	$	—		$	303		$	9,784

	For the Six Months Ended June 30, 2010
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)			Total Assets as of June 30, 2010
Natural Gas Distribution	$	1,995	$	7		$	149		$	4,463
Competitive Natural Gas Sales and Services		1,394		18			9			1,147
Interstate Pipelines		216		70			139			3,568
Field Services		124		24			54			1,428
Other Operations		—		—			(2	)		539
Eliminations		—		(119	)		—			(1,476	)
Consolidated	$	3,729	$	—		$	349		$	9,669

(15)	Other Current Assets and Liabilities

Included in other current assets on the Condensed Consolidated Balance Sheets at December 31, 2009 and June 30, 2010 was $80 million and $106 million, respectively, of under-recovered gas cost. Included in other current liabilities on the Condensed Consolidated Balance Sheets at December 31, 2009 and June 30, 2010 was $70 million and $157 million, respectively, of over-recovered gas cost.

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

The following narrative analysis should be read in combination with our Interim Condensed Financial Statements contained in Item 1 of this report and our Annual Report on Form 10-K for the year ended December 31, 2009 (2009 Form 10-K).

We meet the conditions specified in General Instruction H(1)(a) and (b) to Form 10-Q and are therefore permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies. Accordingly, we have omitted from this report the information called for by Item 2 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Item 3 (Quantitative and Qualitative Disclosures About Market Risk) of Part I and the following Part II items of Form 10-Q: Item 2 (Unregistered Sales of Equity Securities and Use of Proceeds), Item 3 (Defaults Upon Senior Securities) and Item 4 (Submission of Matters to a Vote of Security Holders). The following discussion explains material changes in our revenue and expense items between the three and six months ended June 30, 2 009 and the three and six months ended June 30, 2010. Reference is made to “Management’s Narrative Analysis of Results of Operations” in Item 7 of our 2009 Form 10-K.

EXECUTIVE SUMMARY

Recent Events

Long-Term Gas Gathering and Treating Agreements

In September 2009, CenterPoint Energy Field Services, Inc. (CEFS), 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 certain Haynesville Shale and Bossier Shale formations in Louisiana. CEFS also acquired jointly-owned gathering facilities from Encana and Shell in De Soto and Red River parishes in northwest Louisiana. Each of the agreements includes acreage dedication and volume commitments for which CEFS has exclusive rights to gather Shell’s and Encana’s natural gas production. The gathering facilities are known as the “Magn olia Gathering System.”

In connection with the agreements, CEFS commenced gathering and treating services utilizing the acquired facilities. CEFS is expanding the acquired facilities in order to gather and treat up to 700 million cubic feet (MMcf) per day of natural gas and expects to place the majority of those facilities in service in the third quarter of 2010 with only well connects remaining. CEFS estimates that the purchase of existing facilities and construction to gather 700 MMcf per day will cost up to $325 million. As of June 30, 2010, approximately $286 million has been spent on the original project scope, including the purchase of existing facilities.

Under the agreements, Encana or Shell can elect to require CEFS to further expand the facilities in order to gather and treat a total volume of up to 1 billion cubic feet (Bcf) per day, and in March 2010, Encana and Shell exercised initial expansion elections to increase gathering capacity by 200 MMcf per day to 900 MMcf. Total capital expenditures for this expansion are estimated to be approximately $60 million, and the increased capacity is expected to be in service by the first quarter of 2011. In connection with the expansion, Encana and Shell each made incremental volume commitments for the capacity expansion.

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

Financial Reform Legislation

On July 21, 2010 the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank), which makes substantial changes to regulatory oversight regarding banks and financial institutions. Many provisions of Dodd-Frank will also affect non-financial businesses such as those conducted by us and our subsidiaries. It is not possible at this time to predict the ultimate impacts this legislation may have on us and our subsidiaries since most of the provisions in the law will require extensive rulemaking by various regulatory agencies and authorities, including, among others, the Securities and Exchange Commission (SEC) and the New York Stock Exchange (NYSE). Nevertheless, in a number of areas, the resulting rules are expected to have direct or indirect impacts on our businesses.

Although Dodd-Frank includes significant new provisions regarding the regulation of derivatives, the impact of those requirements will not be known definitively until regulations have been adopted by the SEC and the Commodities Futures Trading Commission. Nevertheless, from the language of Dodd-Frank and its legislative history, it does not appear that our derivatives trading activities will be subject to substantially more regulation than is currently in place, though the new regulations may increase the costs associated with trading and/or decrease the number of available trading counterparties.

Dodd-Frank also makes substantial changes to the regulatory oversight of the credit rating agencies that are typically engaged to rate our securities. Those provisions include the elimination of certain exemptions the credit agencies have previously enjoyed from liabilities under the securities laws, the treatment of ratings agencies as “experts” when their ratings are used in connection with securities offerings and the elimination of a safe harbor under Regulation FD for information provided to credit rating agencies. Following enactment of Dodd-Frank, the three principal rating agencies announced that they would not consent to the inclusion of their ratings in registered public offerings of securities, but the SEC has issued guidance that mitigates, at least for the present time, the impacts of the new restr ictions on some securities offerings. It is presently unknown what effect implementation of these new provisions ultimately will have on the activities or costs associated with the credit rating process.

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 six months ended June 30, 2009 and 2010, followed by a discussion of our consolidated results of operations.

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2010			2009			2010
	(in millions)
Revenues	$	1,116		$	1,191		$	3,467		$	3,729
Expenses:
Natural gas		710			778			2,499			2,713
Operation and maintenance		223			214			456			446
Depreciation and amortization		57			63			114			123
Taxes other than income taxes		37			35			95			98
Total Expenses		1,027			1,090			3,164			3,380
Operating Income		89			101			303			349
Interest and Other Finance Charges		(53	)		(52	)		(107	)		(103	)
Equity in earnings of unconsolidated affiliates		11			7			11			12
Other Income, net		2			—			3			—
Income Before Income Taxes		49			56			210			258
Income Tax Expense		(15	)		(23	)		(81	)		(119	)
Net Income	$	34		$	33		$	129		$	139

Three months ended June 30, 2010 compared to three months ended June 30, 2009

We reported net income of $33 million for the three months ended June 30, 2010 compared to $34 million for the same period in 2009. The decrease in net income of $1 million was primarily due to an $8 million increase in income tax expense and a $4 million decrease in equity in earnings of unconsolidated affiliates, partially offset by a $12 million increase in operating income from our business segments as discussed below.

Six months ended June 30, 2010 compared to six months ended June 30, 2009

We reported net income of $139 million for the six months ended June 30, 2010 compared to $129 million for the same period in 2009. The increase in net income of $10 million was primarily due to a $46 million increase in operating income from our business segments as discussed below, partially offset by a $38 million increase in income tax expense.

Income Tax Expense. During the three and six months ended June 30, 2009, the effective tax rate was 30% and 39%, respectively. During the three and six months ended June 30, 2010, the effective tax rate was 41% and 46%, respectively. The comparability of the effective tax rate for the three months ended June 30, 2009 and 2010 is primarily affected by a $3 million tax benefit related to an adjustment to deferred state tax liabilities in 2009. The comparability of the effective tax rate for the six months ended June 30, 2009 and 2010 is primarily affected by a non-cash, $19 million increase in the 2010 income tax expense as a result of a change in tax law upon the enactment in March 2010 of the Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act of 2010.

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

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (loss) for each of our business segments for the three and six months ended June 30, 2009 and 2010 (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 June 30,						Six Months Ended June 30,
	2009			2010			2009			2010
Natural Gas Distribution	$	2		$	10		$	120		$	149
Competitive Natural Gas Sales and Services		6			(6	)		8			9
Interstate Pipelines		61			67			130			139
Field Services		23			31			49			54
Other Operations		(3	)		(1	)		(4	)		(2	)
Total Consolidated Operating Income	$	89		$	101		$	303		$	349

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 six months ended June 30, 2009 and 2010 (in millions, except throughput and customer data):

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2010		2009		2010
Revenues	$	518	$	465	$	1,939	$	2,002
Expenses:
Natural gas		295		244		1,340		1,383
Operation and maintenance		152		144		321		311
Depreciation and amortization		41		44		81		84
Taxes other than income taxes		28		23		77		75
Total expenses		516		455		1,819		1,853
Operating Income	$	2	$	10	$	120	$	149

Throughput (in Bcf):
Residential		20		16		98		112
Commercial and industrial		46		49		123		136
Total Throughput		66		65		221		248

Number of customers at period end:
Residential		2,961,941		2,973,013		2,961,941		2,973,013
Commercial and industrial		241,875		244,089		241,875		244,089
Total		3,203,816		3,217,102		3,203,816		3,217,102

Three months ended June 30, 2010 compared to three months ended June 30, 2009

Our Natural Gas Distribution business segment reported operating income of $10 million for the three months ended June 30, 2010 compared to $2 million for the three months ended June 30, 2009. Operating income increased $8 million primarily as a result of rate increases ($6 million), lower pension and other benefits costs ($4 million), higher non-volumetric revenues ($2 million) and lower bad debt expense ($2 million). These were partially offset by lower throughput ($4 million), primarily caused by warmer weather, and increased labor costs ($3 million).

Six months ended June 30, 2010 compared to six months ended June 30, 2009

Our Natural Gas Distribution business segment reported operating income of $149 million for the six months ended June 30, 2010 compared to operating income of $120 million for the six months ended June 30, 2009.

Operating income increased $29 million primarily as a result of rate increases ($10 million), higher throughput ($8 million), including the effect of adding 11,000 residential customers, lower bad debt expense ($7 million) in part due to improved collection efforts, lower pension and other benefits costs ($6 million) and increased non-volumetric revenues ($4 million). These were partially offset by higher labor costs ($5 million).

Competitive Natural Gas Sales and Services

For information regarding factors that may affect the future results of operations of our Competitive Natural Gas Sales and Services business segment, please read "Risk Factors ─ Risk Factors Affecting Our Businesses," "─ Risk Factors Associated with Our Consolidated Financial Condition" and "─ Other Risks" in Item 1A of Part 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 six months ended June 30, 2009 and 2010 (in millions, except throughput and customer data):

	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2010			2009		2010
Revenues	$	432	$	560		$	1,197	$	1,412
Expenses:
Natural gas		414		554			1,166		1,380
Operation and maintenance		10		10			20		19
Depreciation and amortization		1		1			2		2
Taxes other than income taxes		1		1			1		2
Total expenses		426		566			1,189		1,403
Operating Income (Loss)	$	6	$	(6	)	$	8	$	9

Throughput (in Bcf)		114		128			255		269

Number of customers at period end		10,878		11,694			10,878		11,694

Three months ended June 30, 2010 compared to three months ended June 30, 2009

Our Competitive Natural Gas Sales and Services business segment reported an operating loss of $6 million for the three months ended June 30, 2010 compared to operating income of $6 million for the three months ended June 30, 2009. The decrease in operating income of $12 million is primarily due to the unfavorable impact of the mark-to-market valuation for non-trading financial derivatives for the second quarter of 2010 of $8 million versus a favorable impact of $3 million for the same period in 2009.

Six months ended June 30, 2010 compared to six months ended June 30, 2009

Our Competitive Natural Gas Sales and Services business segment reported operating income of $9 million for the six months ended June 30, 2010 compared to $8 million for the six months ended June 30, 2009. The increase in operating income of $1 million was due to the improvement of the unfavorable impact of the mark-to-market valuation for non-trading financial derivatives for the first six months of 2010 of $5 million versus $16 million for the same period in 2009. A further favorable impact of $5 million is attributable to the $6 million write down of natural gas inventory in the first half of 2009 to the lower of cost or market as compared to a write down of less than $1 million in the first half of 2010. Offsetting these increases to operating income is a $15& #160;million decrease in margin attributable to reduced basis spreads on pipeline transport opportunities and decreased seasonal storage spreads.

Interstate Pipelines

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

The following table provides summary data of our Interstate Pipelines business segment for the three and six months ended June 30, 2009 and 2010 (in millions, except throughput data):

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2010		2009		2010
Revenues	$	155	$	148	$	308	$	286
Expenses:
Natural gas		34		24		63		34
Operation and maintenance		41		35		76		70
Depreciation and amortization		12		13		24		26
Taxes other than income taxes		7		9		15		17
Total expenses		94		81		178		147
Operating Income	$	61	$	67	$	130	$	139

Transportation throughput (in Bcf) :		396		400		857		838

Three months ended June 30, 2010 compared to three months ended June 30, 2009

Our Interstate Pipeline business segment reported operating income of $67 million for the three months ended June 30, 2010 compared to $61 million for the three months ended June 30, 2009. Margins (revenues less natural gas costs) increased $3 million primarily due to new contracts for the phase IV Carthage to Perryville pipeline expansion ($12 million), partially offset by reduced off-system transportation margins and ancillary services ($9 million). Lower operations and maintenance expenses ($6 million) were partially offset by higher depreciation and amortization expenses ($1 million) related to asset additions and increased taxes other than income taxes ($2 million).

Equity Earnings. In addition, this business segment recorded equity income of $9 million and $4 million for the three months ended June 30, 2009 and 2010, respectively, from its 50% interest in the Southeast Supply Header (SESH), a jointly-owned pipeline that went into service in September 2008. The second quarter of 2009 benefited from the receipt of a one-time fee related to the construction of the pipeline and a reduction in estimated property taxes. Our 50% share of those amounts was approximately $5 million. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Six months ended June 30, 2010 compared to six months ended June 30, 2009

Our Interstate Pipeline business segment reported operating income of $139 million for the six months ended June 30, 2010 compared to $130 million for the six months ended June 30, 2009. Margins increased by $7 million primarily due to new contracts for the phase IV Carthage to Perryville pipeline expansion ($24 million) and new power plant transportation contracts ($2 million), partially offset by reduced ancillary services and off-system transportation margins ($19 million). Lower operation and maintenance expenses ($6 million) were partially offset by increased depreciation and amortization expenses ($2 million) related to new assets and increased taxes other than income taxes ($2 million).

Equity Earnings. In addition, this business segment recorded equity income of $7 million for both the six months ended June 30, 2009 and 2010, from its 50% interest in SESH. The 2009 results include a non-cash pre-tax charge of $5 million to reflect SESH’s discontinued use of guidance for accounting for regulated operations which was largely offset by the receipt of a one-time fee in the second quarter of 2009 related to the construction of the pipeline and reduced property taxes totaling approximately $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 six months ended June 30, 2009 and 2010 (in millions, except throughput data):

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2010		2009		2010
Revenues	$	56	$	80	$	113	$	148
Expenses:
Natural gas		11		18		18		34
Operation and maintenance		18		25		37		46
Depreciation and amortization		3		5		7		11
Taxes other than income taxes		1		1		2		3
Total expenses		33		49		64		94
Operating Income	$	23	$	31	$	49	$	54

Gathering throughput (in Bcf) :		102		156		206		284

Three months ended June 30, 2010 compared to three months ended June 30, 2009

Our Field Services business segment reported operating income of $31 million for the three months ended June 30, 2010 compared to $23 million for the three months ended June 30, 2009. Increased margins from new projects and core gathering services ($12 million) and increased commodity prices ($5 million) more than offset the increase in operating expenses ($9 million) associated with new projects.

Equity Earnings. In addition, this business segment recorded equity income of $2 million and $3 million in the three months ended June 30, 2009 and 2010, respectively, from its 50% interest in a jointly-owned gas processing plant. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Six months ended June 30, 2010 compared to six months ended June 30, 2009

Our Field Services business segment reported operating income of $54 million for the six months ended June 30, 2010 compared to $49 million for the six months ended June 30, 2009. Increased margins from new projects and core gathering services ($15 million) and increased commodity prices ($4 million) more than offset the increase in operating expenses ($14 million) associated with new projects.

Equity Earnings. In addition, this business segment recorded equity income of $4 million and $5 million in the six months ended June 30, 2009 and 2010, respectively, from its 50% interest in a jointly-owned gas processing plant. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

For information on other developments, factors and trends that may have an impact on our future earnings, please read “Risk Factors” in Item 1A of Part 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 2009 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, working capital needs, various regulatory actions and appeals relating to such actions. Our principal anticipated cash requirements for the remaining six months of 2010 include approximately $440 million of capital expenditures.

We expect that borrowings under our credit facility, advances under our receivables facility, anticipated cash flows from operations and borrowings from affiliates will be sufficient to meet our anticipated cash needs for the remaining six months of 2010. Cash needs or discretionary financing or refinancing may result in the issuance of debt securities in the capital markets or the arrangement of additional credit facilities. Issuances of debt in the capital markets and additional credit facilities may not, however, be available to us on acceptable terms.

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

Prior to CenterPoint Energy’s distribution of its ownership in RRI Energy, Inc. (formerly known as Reliant Energy, Inc. and Reliant Resources, Inc.) (RRI) to its shareholders, we had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure us against obligations under the guaranties RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI has agreed to provide to us cash or letters of credit as security against our obligations under our remaining guaranties for demand charges under certain gas purchase and transportation agreements if and to the extent changes in market conditions expose us to a risk of loss on those guaranties. The present value of the d emand charges under these transportation contracts, which will be in effect until 2018, was approximately $89 million as of June 30, 2010. As of June 30, 2010, 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. As of July 26, 2010, we had the following facilities (in millions):

Date Executed	Type of Facility	Size of Facility		Amount Utilized at July 26, 2010		Termination Date
June 29, 2007	Revolver	$	915	$	—	June 29, 2012
October 9, 2009	Receivables		215		—	October 8, 2010

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

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

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

CERC Corp.’s $915 million credit facility backstops a $915 million commercial paper program under which we began issuing commercial paper in February 2008. 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.

Securities Registered with the SEC. At July 26, 2010, we had a shelf registration statement covering $500 million principal amount of senior debt securities.

Temporary Investments. As of July 26, 2010, we had no external temporary investments.

Money Pool. We participate in a money pool through which we and certain of our affiliates can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings by CenterPoint Energy under its revolving credit facility or the sale by CenterPoint Energy of its commercial paper. At July 26, 2010, we had borrowings of $470 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. The interest rate on borrowings under our credit facility is based on our credit facility. As of August 3, 2010, Moody’s Investors Service, Inc. (Moody’s), Standard & Poor’s Rating Services, a division of The McGraw Hill Companies (S&P), and Fitch, Inc. (Fitch) had assigned the following credit ratings to our senior unsecured debt:

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

__________

(1)

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

(2)

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

(3)

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

We cannot assure you that the ratings set forth above 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 included for informational purposes and 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.

A decline in these credit ratings could increase borrowing costs under our $915 million credit facility. If our credit ratings had been downgraded one notch by each of the three principal credit rating agencies from the ratings that existed at June 30, 2010, the impact on the borrowing costs under our credit facility would have been immaterial. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact our ability to complete capital market transactions. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments.

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

CenterPoint Energy Services, Inc. (CES), our wholly owned subsidiary operating in our Competitive Natural Gas Sales and Services business segment, provides comprehensive natural gas sales and services primarily to commercial and industrial customers and electric and gas utilities throughout the central and eastern United States. In order to economically hedge its exposure to natural gas prices, CES uses derivatives with provisions standard for the industry, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each

counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the 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 June 30, 2010, the amount posted as collateral aggregated approximately $132 million ($85 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 June 30, 2010, unsecured credit limits extended to CES by counterparties agg regate $243 million; however, utilized credit capacity was $81 million.

Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, we might need to provide cash or other collateral of as much as $183 million as of June 30, 2010. The amount of collateral will depend on seasonal variations in transportation levels.

Cross Defaults. Under CenterPoint Energy’s revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $50 million by us will cause a default. In addition, four outstanding series of CenterPoint Energy’s senior notes, aggregating $950 million in principal amount as of June 30, 2010, provide that a payment default by us in respect of, or an acceleration of, borrowed money and certain other specified types of obligations, in the aggregate principal amount of $50 million, will cause a default. A default by CenterPoint Energy would not trigger a default under our debt instruments or bank credit facilities.

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

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

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

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

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increased costs related to the acquisition of natural gas;

•

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

•

various regulatory actions;

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incremental collateral, if any, that may be required due to regulation of derivatives;

•

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

•

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

•

the ability of RRI and its subsidiaries to satisfy their obligations in respect of RRI’s indemnity obligations

to us and our subsidiaries or in connection with the contractual obligations to a third party pursuant to which we are their guarantor;

•

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

•

the outcome of litigation brought by and against us;

•

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

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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. Our revolving credit facility and our receivables facility limit our debt as a percentage of our total capitalization to 65%.

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

NEW ACCOUNTING PRONOUNCEMENTS

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

Item 4. CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2010 to provide assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and such information is accumulated and communi cated 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 June 30, 2010 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

For a discussion of material legal and regulatory proceedings affecting us, please read Notes 4 and 11 to our Interim Condensed Financial Statements, each of which is incorporated herein by reference. See also “Business — Regulation” and “— Environmental Matters” in Item 1 and “Legal Proceedings” in Item 3 of our 2009 Form 10-K.

Item 1A. RISK FACTORS

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 2009 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 2009 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.

Our 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, but recently, environmental considerations have grown in importance when consumers consider other forms of energy. 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, finan cial 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 and transportation 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 le vels. Additionally, a decrease in natural gas prices could increase the amount of collateral that we must provide under our hedging arrangements.

A decline in our credit rating could result in our having to provide collateral in order to purchase natural 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 and regulatory and other issues impacting our customers’ production decisions.

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 relat ive to other available production, producers’ access to needed capital and the cost of that capital, access to drilling rigs, the ability of producers to obtain necessary drilling and other governmental permits and regulatory changes. Regulatory changes include the potential for more restrictive rules governing the use of hydraulic fracturing, a process used in the extraction of natural gas from shale reservoir formations, and the use of groundwater in that process. 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.

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 business 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 ra ting.

These regulatory frameworks could have adverse effects on our ability to conduct our utility operations, to finance our business and to provide cost-effective utility service. In addition, if more than one state adopts restrictions on 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 June 30, 2010, we had $2.8 billion of outstanding indebtedness on a consolidated basis. As of June 30, 2010, approximately $550 million principal amount of this debt is required to be paid through 2012, excluding $342 million borrowed from the money pool. Our future financing activities may be significantly affected by, among other things:

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general economic and capital market conditions;

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credit availability from financial institutions and other lenders;

•

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

•

maintenance of acceptable credit ratings by us and CenterPoint Energy;

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market expectations regarding our future earnings and cash flows;

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

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our exposure to RRI in connection with its indemnification obligations arising in connection with its separation from CenterPoint Energy; 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 report. 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.

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 parent company and our affiliates. As of June 30, 2010, CenterPoint Energy and its subsidiaries other than us have approximately $265 million principal amount of debt required to be paid through 2012. This amount excludes amounts related to capital leases and principal repayments of approximately $724 million on transition and system restoration bonds for which a dedicated revenue stream exists. 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;

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decisions on our financings and our capital raising activities;

•

mergers or other business combinations; and

•

our acquisition or disposition of assets.

Other than the financial covenants contained in our credit facility and receivables facility (described under “Liquidity and Capital Resources” in Item 2 of Part I of this report), which could have the practical effect of limiting the payment of dividends under certain circumstances, 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. As a result, we depend, in part, on distributions from our subsidiaries in order to meet our payment obligations. 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 could be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by us.

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:

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restricting the way we can handle or dispose of wastes;

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

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

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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:

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construct or acquire new equipment;

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acquire permits for facility operations;

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modify or replace existing and proposed equipment; and

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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.

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 con nection 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 to us cash or letters of credit as security against our obligations under our remaining guaranties for demand charges under certain gas transportation agreements if and to the extent changes in market conditions expose us to a risk of loss on those guaranties. The present value of the demand charges under these transportation contracts, which will be in effect until 2018, was approximately $89 million as of June 30, 2010. As of June 30, 2010, 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.

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 CenterPoint Energy as its former owner.

In May 2009, RRI sold its Texas retail business to NRG Retail LLC, a subsidiary of NRG Energy, Inc. In connection with the sale, RRI changed its name to RRI Energy, Inc. In April 2010, RRI announced its plan to merge with Mirant Corporation in an all-stock transaction. Neither the sale of the retail business nor the merger with Mirant Corporation, if ultimately finalized, alters RRI’s contractual obligations to indemnify CenterPoint Energy and its subsidiaries, including us, 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.

Reliant Energy and RRI are named as defendants in a number of lawsuits arising out of sales of natural gas in California and other markets. Although these matters relate to the business and operations of RRI, claims against Reliant Energy have been made on grounds that include liability of Reliant Energy as a controlling shareholder of RRI. We and CenterPoint Energy could incur liability if claims in one or more of these lawsuits were successfully asserted against us and 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 unsettled conditions in the global financial system may have impacts on our business, liquidity and financial condition that we currently cannot predict.

The recent credit crisis and unsettled conditions in the global financial system may have an impact on our business, liquidity and 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 may be materially adversely impacted by these market conditions. Defaults of lenders in our credit facilities, should they further 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 reductio ns increased non-cash pension expense in 2009 which impacted 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, a recurrence of 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.

Climate change legislation and regulatory initiatives could result in increased operating costs and reduced demand for our services.

Legislation to regulate emissions of greenhouse gases has been introduced in Congress, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues, such as the United Nations Climate Change Conference in Copenhagen in 2009. Also, the EPA has undertaken new efforts to collect information regarding greenhouse gas emissions and their effects. Recently, the EPA declared that certain greenhouse gases represent an endangerment to human health and proposed to expand its regulations relating to those emissions. It is too earl y to determine whether, or in what form, further regulatory action regarding greenhouse gas emissions will be adopted or what specific impacts a new regulatory action might have on us and our subsidiaries. However, as a distributor and transporter of natural gas and consumer of natural gas in our pipeline and gathering businesses, our revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of our operations or would have the effect of reducing the consumption of natural gas. Likewise, incentives to conserve energy or use energy sources other than natural gas could result in a decrease in demand for our services.

Climate changes could result in more frequent severe weather events and warmer temperatures which could adversely affect the results of operations of our businesses.

To the extent climate changes occur, our businesses may be adversely impacted, though we believe any such impacts are likely to occur very gradually and hence would be difficult to quantify with specificity. To the extent global climate change results in warmer temperatures in our service territories, financial results from our natural gas distribution businesses could be adversely affected through lower gas sales, and our gas transmission and field services businesses could experience lower revenues. Another possible climate change is the possibility of more frequent and more severe weather events, such as hurricanes or tornadoes. Since many of our facilities are located along or near the Gulf Coast, increased or more severe hurricanes or tornadoes can increase our costs to repair damaged facilities and restore service to our customers. When we cannot deliver natural gas to customers or our customers cannot receive our services, our financial results can be impacted by lost revenues, and we generally must seek approval from regulators to recover restoration costs. To the extent we are unable to recover those costs, or if higher rates resulting from our recovery of such costs result in reduced demand for our services, our future financial results may be adversely impacted.

Item 5. OTHER INFORMATION

Our ratio of earnings to fixed charges for the six months ended June 30, 2009 and 2010 was 2.78 and 3.24, respectively. We do not believe that the ratios for these six-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
+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

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: August 11, 2010

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

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Centerpoint Energy Resources 10-Q2010 Q2 Quarterly report

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