Centerpoint Energy Resources 10-Q 2011 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, 2011
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 þ  No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See 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 15, 2011, 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, 2011

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements	1
	Condensed Statements of Consolidated Income
	Three and Six Months Ended June 30, 2010 and 2011 (unaudited)	1
	Condensed Consolidated Balance Sheets
	December 31, 2010 and June 30, 2011 (unaudited)	2
	Condensed Statements of Consolidated Cash Flows
	Six Months Ended June 30, 2010 and 2011 (unaudited)	4
	Notes to Unaudited Condensed Consolidated Financial Statements	5
Item 2.	Management’s Narrative Analysis of Results of Operations	21
Item 4.	Controls and Procedures	30
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	31
Item 1A.	Risk Factors	31
Item 5.	Other Information	31
Item 6.	Exhibits	31

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

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

• state and federal legislative and regulatory actions or developments 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, pipeline integrity and safety, health care reform, financial reform and tax legislation;

• 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 and other proceedings related 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, and the effects of geographic and seasonal commodity price differentials;

• 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;

• 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 credit 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;

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• the ability of GenOn Energy, Inc. (GenOn) (formerly known as RRI Energy, Inc., Reliant Energy, Inc. and Reliant Resources, Inc.) and its subsidiaries to satisfy their obligations to us, including indemnity obligations, or obligations 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 you will be completed or will have the anticipated benefits to us;

• acquisition and merger activities involving us or our competitors; and

· other factors we discuss in “Risk Factors” in Item 1A of Part I of our Annual Report on Form 10-K for the year ended December 31, 2010, which is incorporated herein by reference, and other reports we file from time to time with the Securities and Exchange Commission.

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

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PART I. FINANCIAL INFORMATION

Item 1.     FINANCIAL STATEMENTS

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Millions of Dollars)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2011			2010			2011
Revenues	$	1,191		$	1,228		$	3,729		$	3,323
Expenses:
Natural gas		778			778			2,713			2,254
Operation and maintenance		214			237			446			477
Depreciation and amortization		63			65			123			131
Taxes other than income taxes		35			34			98			87
Total		1,090			1,114			3,380			2,949
Operating Income		101			114			349			374
Other Income (Expense):
Interest and other finance charges		(52	)		(45	)		(103	)		(94	)
Equity in earnings of unconsolidated affiliates		7			8			12			14
Other, net		—			1			—			2
Total		(45	)		(36	)		(91	)		(78	)
Income Before Income Taxes		56			78			258			296
Income tax expense		23			31			119			116
Net Income	$	33		$	47		$	139		$	180

See Notes to the Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

(Unaudited)

ASSETS

	December 31, 2010		June 30, 2011
Current Assets:
Cash and cash equivalents	$	1	$	5
Accounts and notes receivable, net		603		453
Accrued unbilled revenue		270		74
Accounts and notes receivable – affiliated companies		19		15
Materials and supplies		93		92
Natural gas inventory		211		144
Non-trading derivative assets		54		39
Taxes receivable		63		2
Deferred tax asset		48		43
Prepaid expenses and other current assets		208		123
Total current assets		1,570		990
Property, Plant and Equipment:
Property, plant and equipment		7,939		8,189
Less accumulated depreciation and amortization		1,303		1,396
Property, plant and equipment, net		6,636		6,793
Other Assets:
Goodwill		1,696		1,696
Non-trading derivative assets		15		11
Investment in unconsolidated affiliates		468		474
Other		153		131
Total other assets		2,332		2,312
Total Assets	$	10,538	$	10,095

See Notes to the Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED BALANCE SHEETS — (Continued)

(Millions of Dollars)

(Unaudited)

LIABILITIES AND STOCKHOLDER’S EQUITY

	December 31, 2010			June 30, 2011
Current Liabilities:
Short-term borrowings	$	53		$	109
Accounts payable		573			309
Accounts and notes payable — affiliated companies		541			471
Taxes accrued		73			74
Interest accrued		51			48
Customer deposits		76			76
Non-trading derivative liabilities		68			46
Other		255			139
Total current liabilities		1,690			1,272
Other Liabilities:
Accumulated deferred income taxes, net		1,319			1,389
Non-trading derivative liabilities		16			4
Benefit obligations		100			98
Regulatory liabilities		572			599
Other		140			146
Total other liabilities		2,147			2,236
Long-term Debt		2,925			2,631
Commitments and Contingencies (Note 11)
Stockholder’s Equity:
Common stock		—			—
Paid-in capital		2,416			2,416
Retained earnings		1,365			1,545
Accumulated other comprehensive loss		(5	)		(5	)
Total stockholder’s equity		3,776			3,956
Total Liabilities and Stockholder’s Equity	$	10,538		$	10,095

See Notes to the Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Millions of Dollars)

(Unaudited)

	Six Months Ended June 30,
	2010			2011
Cash Flows from Operating Activities:
Net income	$	139		$	180
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		123			131
Amortization of deferred financing costs		4			6
Deferred income taxes		(1	)		75
Equity in earnings of unconsolidated affiliates, net of distributions		6			1
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net		434			305
Accounts receivable/payable, affiliates		(12	)		(6	)
Inventory		24			68
Taxes receivable		47			61
Accounts payable		(236	)		(213	)
Fuel cost over (under) recovery		93			(19	)
Interest and taxes accrued		50			(2	)
Non-trading derivatives, net		3			—
Margin deposits, net		(18	)		48
Other current assets		(6	)		19
Other current liabilities		(14	)		(28	)
Other assets		1			4
Other liabilities		(8	)		7
Other, net		—			1
Net cash provided by operating activities		629			638
Cash Flows from Investing Activities:
Capital expenditures		(449	)		(318	)
Investment in unconsolidated affiliates		(22	)		(7	)
Other, net		(1	)		1
Net cash used in investing activities		(472	)		(324	)
Cash Flows from Financing Activities:
Decrease in short-term borrowings, net		(23	)		(14	)
Proceeds from commercial paper, net		—			(113	)
Proceeds from long-term debt		—			550
Payments of long-term debt		(45	)		(606	)
Cash paid for debt exchange		—			(58	)
Debt issuance costs		—			(9	)
Decrease in notes payable to affiliates		(89	)		(60	)
Net cash used in financing activities		(157	)		(310	)
Net Increase in Cash and Cash Equivalents		—			4
Cash and Cash Equivalents at Beginning of Period		1			1
Cash and Cash Equivalents at End of Period	$	1		$	5
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	97		$	90
Income taxes (refunds), net		15			(19	)
Non-cash transactions:
Accounts payable related to capital expenditures		61			47

See Notes to the Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1)           Background and Basis of Presentation

General.  Included in this Quarterly Report on Form 10-Q (Form 10-Q) of CenterPoint Energy Resources Corp. (CERC Corp.) are the condensed consolidated interim financial statements and notes (Interim Condensed Financial Statements) of CenterPoint Energy Resources Corp. and its subsidiaries (collectively, CERC).  The Interim Condensed Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the Annual Report on Form 10-K of CERC Corp. for the year ended December 31, 2010 (CERC Corp. Form 10-K).

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

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

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

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

For a description of CERC's reportable business segments, see Note 13.

(2)           New Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board (FASB) issued new accounting guidance to require additional fair value related disclosures. It also clarified existing fair value disclosure guidance about the level of disaggregation, inputs and valuation techniques. This new guidance was effective for the first reporting period beginning after December 15, 2009 except for certain disclosure requirements effective for the first reporting period beginning after December 15, 2010. The adoption of this new guidance did not have a material impact on CERC’s financial position, results of operations or cash flows. See Note 6 for the required disclosures.

In May 2011, the FASB issued new accounting guidance to achieve common fair value measurements and disclosure requirements in U.S. GAAP and International Financial Reporting Standards (IFRS). Some of the provisions of the new accounting guidance include requiring (1) that only nonfinancial assets should be valued based on a determination of their best use, (2) disclosure of quantitative information about unobservable inputs used in Level 3 fair value measurements and (3) disclosure of the level within the fair value hierarchy for each class of assets or liabilities not measured at fair value in the statement of financial position but for which the fair value is disclosed. This new guidance is effective for interim and annual periods beginning after December 15, 2011. CERC expects that the adoption of this new guidance will not have a material impact on its financial position, results of operations or cash flows.

In June 2011, the FASB issued new accounting guidance on the presentation of comprehensive income. The new guidance is intended to improve the overall quality of financial reporting by increasing the prominence of items reported in other comprehensive income and aligning the presentation of other comprehensive income in financial

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statements prepared in accordance with U.S. GAAP with those prepared in accordance with IFRS. The new guidance requires an entity to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. This new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. CERC expects that the adoption of this new guidance will not have a material impact on its financial position, results of operations or cash flows.

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,
	2010		2011		2010		2011
	(in millions)
Interest cost	$	1	$	2	$	3	$	3
Amortization of prior service cost		1		—		1		1
Net periodic cost	$	2	$	2	$	4	$	4

CERC expects to contribute approximately $8 million to its postretirement benefit plan in 2011, of which $2 million and $6 million, respectively, was contributed during the three and six months ended June 30, 2011.

 (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 approved 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 court 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 Texas Third Court of Appeals at Austin, Texas. Oral arguments were held in February 2011. 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. The cost of service adjustment was initially effective for three successive years ending in calendar year 2010, but would automatically renew for successive three-year periods unless Gas Operations or the regulatory authority having original jurisdiction gave written notice to discontinue the adjustment mechanism by February 1, 2011. Certain cities that agreed to the initial implementation notified Gas Operations by February 1, 2011 of their desire to discontinue the adjustment mechanism. In July 2011, Gas Operations requested that the Railroad Commission waive the notice date of February 1, 2011 in order to allow Gas Operations to discontinue the cost of service adjustment mechanism for the remaining areas.

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, and would be subject to an annual cost of service adjustment. 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 other employee benefits, accumulated deferred income

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taxes and other items. The Railroad Commission also approved a surcharge of $0.9 million per year to recover costs associated with damage caused by Hurricane Ike 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.

In December 2010, Gas Operations filed a request to change its rates with the Railroad Commission and the 66 cities in its South Texas service territory, consisting of approximately 137,000 customers. 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 approximately $6.1 million.  The parties reached a settlement resulting in increased revenues of $4.6 million, which was approved by the Railroad Commission in April 2011.  The new rates were implemented effective May 2011.

Other. Gas Operations has various periodic rate adjustment mechanisms available for use in certain of the jurisdictions in which it operates. In March 2011, Gas Operations made its Annual Billing Determinant Adjustment filing with the Arkansas Public Service Commission (APSC) requesting an annual increase in base rates of $5.9 million to collect the amounts accrued in 2010 for recovery of declines in revenues as a result of lower volumes and number of customers.  The increase became effective in June 2011.

In June 2011, the APSC approved Gas Operations’ requested Energy Efficiency Cost Recovery rider, which enables recovery of the cost of Gas Operations’ energy efficiency programs, lost contributions to fixed costs and an incentive based on the results of the energy efficiency programs.  The order also extended the use of the existing decoupling mechanism until December 31, 2013.

(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 the 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, 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 three months ended June 30, 2011, CERC recorded decreased natural gas revenues from unrealized net losses of $2 million and decreased natural gas expense from unrealized net gains of $6 million, resulting in a net unrealized gain of $4 million.  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.  During the six months

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ended June 30, 2011, CERC recorded decreased natural gas revenues from unrealized net losses of $19 million and decreased natural gas expense from unrealized net gains of $21 million, resulting in a net unrealized gain of $2 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 Gas Operations’ results 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, 2010, CERC recognized gains of $2 million and losses of $5 million, respectively, related to these swaps. During the three and six months ended June 30, 2011, CERC recognized losses of $1 million and $6 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 two tables provide a balance sheet overview of CERC’s Derivative Assets and Liabilities as of December 31, 2010 and June 30, 2011, while the last table provides a breakdown of the related income statement impacts for the three and six months ended June 30, 2010 and 2011.

Fair Value of Derivative Instruments
		December 31, 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	$	55	$	1
Natural gas contracts (1)	Other Assets		15		—
Natural gas contracts (1)	Current Liabilities		10		143
Natural gas contracts (1)	Other Liabilities		—		35
Total		$	80	$	179

(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 626 billion cubic feet (Bcf) or a net 72 Bcf long position.  Of the net long position, basis swaps constitute 63 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment comprise 26 Bcf.

(3) The net of total non-trading derivative assets and liabilities is a $15 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 $84 million.

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Fair Value of Derivative Instruments
		June 30, 2011
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	$	42	$	3
Natural gas contracts (1)	Other Assets		11		—
Natural gas contracts (1)	Current Liabilities		8		93
Natural gas contracts (1)	Other Liabilities		1		7
Total		$	62	$	103

(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 593 Bcf or a net 110 Bcf long position.  Of the net long position, basis swaps constitute 65 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment comprise 14 Bcf.

(3) The net of total non-trading derivative assets and liabilities is a less than $1 million asset 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 $41 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. 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 financial natural gas derivatives and non-retail related physical natural gas derivatives.

Income Statement Impact of Derivative Activity
		Three Months Ended June 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2010			2011
		(in millions)
Natural gas contracts	Gains (Losses) in Revenue	$	5		$	9
Natural gas contracts (1)	Gains (Losses) in Expense: Natural Gas		(31	)		(12	)
Total		$	(26	)	$	(3	)

(1) The Gains (Losses) in Expense: Natural Gas includes $(25) million and $(17) million of costs in 2010 and 2011, respectively, associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered 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	2010			2011
		(in millions)
Natural gas contracts	Gains (Losses) in Revenue	$	49		$	14
Natural gas contracts (1)	Gains (Losses) in Expense: Natural Gas		(92	)		(49	)
Total		$	(43	)	$	(35	)

(1) The Gains (Losses) in Expense: Natural Gas includes $(50) million and $(62) million of costs in 2010 and 2011, respectively, associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered through purchased gas adjustments.

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(c) Credit Risk Contingent Features

CERC enters into financial derivative contracts containing material adverse change provisions.  These provisions could require CERC to post additional collateral if the Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc. credit ratings of CERC Corp. or its subsidiaries are 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, 2010 and June 30, 2011 was $107 million and $57 million, respectively.  The aggregate fair value of assets that are already posted as collateral was $31 million and $13 million, respectively, at December 31, 2010 and June 30, 2011.  If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at December 31, 2010 and June 30, 2011, $76 million and $43 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 below 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 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, 2011, there were no significant transfers between levels.

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The following tables present information about CERC’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of December 31, 2010 and June 30, 2011, 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, 2010
	(in millions)
Assets
Corporate equities	$	1	$	—	$	—	$	—		$	1
Investments, including money market funds		11		—		—		—			11
Natural gas derivatives		—		73		7		(11	)		69
Total assets	$	12	$	73	$	7	$	(11	)	$	81
Liabilities
Natural gas derivatives		8		167		4		(95	)		84
Total liabilities	$	8	$	167	$	4	$	(95	)	$	84

(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 $84 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, 2011
	(in millions)
Assets
Corporate equities	$	2	$	—	$	—	$	—		$	2
Investments, including money market funds		11		—		—		—			11
Natural gas derivatives		3		51		8		(12	)		50
Total assets	$	16	$	51	$	8	$	(12	)	$	63
Liabilities
Natural gas derivatives		5		95		3		(53	)		50
Total liabilities	$	5	$	95	$	3	$	(53	)	$	50

(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 $41 million posted with the same counterparties.

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

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	Three Months Ended June 30,
	2010		2011
	(in millions)
Beginning balance	$	4	$	6
Total unrealized gains (losses):
Included in earnings		—		1
Total settlements, gross (1):
Included in earnings		1		(2	)
Ending balance	$	5	$	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

(1) During both the three months ended June 30, 2010 and 2011, CERC did not have Level 3 purchases or sales.

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	Six Months Ended June 30,
	2010			2011
	(in millions)
Beginning balance	$	(6	)	$	3
Total unrealized gains (losses):
Included in earnings		2			4
Included in regulatory assets		(1	)		—
Total settlements, gross (1):
Included in earnings		1			(2	)
Included in regulatory assets		9			—
Ending balance	$	5		$	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	$	3		$	3

(1) During both the six months ended June 30, 2010 and 2011, CERC did not have Level 3 purchases or sales.

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, 2010				June 30, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	2,925	$	3,158	$	2,631	$	2,840

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(7)           Goodwill

Goodwill by reportable business segment as of both December 31, 2010 and June 30, 2011 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):

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2011		2010		2011
	(in millions)
Net income	$	33	$	47	$	139	$	180
Other comprehensive income:
Adjustment to postretirement plans (net of tax of $-0-, $-0-, $-0- and $-0-)		—		—		—		—
Other comprehensive income		—		—		—		—
Comprehensive income	$	33	$	47	$	139	$	180

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

	December 31, 2010			June 30, 2011
	(in millions)
Adjustment to postretirement plans	$	(5	)	$	(5	)
Total accumulated other comprehensive loss	$	(5	)	$	(5	)

(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 $489 million and $429 million at December 31, 2010 and June 30, 2011, respectively, which are included in accounts and notes payable—affiliated companies in the Condensed Consolidated Balance Sheets.

For each of the three and six months ended June 30, 2010 and 2011, CERC had net interest expense of less than $1 million related to affiliate borrowings.

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 $37 million and $42 million for the three months ended June 30, 2010 and 2011, respectively, and $74 million and $81 million for the six months ended June 30, 2010 and 2011, respectively, and are included primarily in operation and maintenance expenses.

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

(a) Short-term Borrowings

Receivables Facility. Availability under CERC’s receivables facility, which terminates on September 14, 2011, ranges from $160 million to $375 million, reflecting seasonal changes in receivables balances.  As of December 31, 2010 and June 30, 2011, the facility size was $160 million and $300 million, respectively. As of both December 31, 2010 and June 30, 2011, 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 that extend through March 31, 2012. 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 $53 million and $39 million as of December 31, 2010 and June 30, 2011, respectively.

(b) Long-term Debt

CERC Corp. Senior Notes.  In January 2011, CERC Corp. issued $250 million aggregate principal amount of senior notes due 2021 with an interest rate of 4.50% and $300 million aggregate principal amount of senior notes due 2041 with an interest rate of 5.85%.  The proceeds from the issuance of the notes were used for the repayment of $550 million of CERC Corp.’s 7.75% senior notes at their maturity in February 2011. Accordingly, the $550 million senior notes due in February 2011 are reflected as long-term debt as of December 31, 2010.

CERC Corp. Exchange Offer. Also in January 2011, CERC Corp. issued an additional $343 million aggregate principal amount of 4.50% senior notes due 2021 and provided cash consideration of $114 million in exchange for $397 million aggregate principal amount of its 7.875% senior notes due 2013.  The premium of $58 million paid on exchanged notes has been deferred and will be amortized to interest expense over the life of the 4.50% senior notes due 2021.

Revolving Credit Facility.  As of both December 31, 2010 and June 30, 2011, CERC Corp. had no outstanding borrowings under its $915 million credit facility.  As of December 31, 2010 and June 30, 2011, CERC Corp. had commercial paper outstanding of $183 million and $70 million, respectively, which was backstopped by its credit facility.  CERC Corp. was in compliance with all debt covenants as of June 30, 2011.  As a result of the June 29, 2012 expiration date of the revolving credit facility, commercial paper borrowings backstopped by such facility have been classified as long-term debt as of December 31, 2010 and short-term borrowings as of June 30, 2011.

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, limiting debt to 65% of its total capitalization.

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, 2010 and June 30, 2011 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, 2011, minimum payment obligations for natural gas supply commitments are approximately $193 million for the

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remaining six months in 2011, $439 million in 2012, $437 million in 2013, $314 million in 2014, $198 million in 2015 and $412 million after 2015.

(b) Capital Commitments

Magnolia Gathering System.  In September 2009, CenterPoint Energy Field Services, LLC (CEFS) 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.  Pursuant to these agreements, CEFS acquired jointly-owned gathering facilities (the Magnolia Gathering System) from Encana and Shell 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.

During the fourth quarter of 2010, CEFS substantially completed the construction and initial expansion of the Magnolia Gathering System in order to permit the system to gather and treat up to 700 million cubic feet (MMcf) per day of natural gas, with only well connects remaining.  CEFS spent approximately $320 million on the original project scope, including the purchase of the original facilities and is in the second year of the 10-year, 700 MMcf per day volume commitment made by Shell and Encana which commenced in September 2009.

Pursuant to an expansion election made by Encana and Shell in March 2010, CEFS expanded the Magnolia Gathering System to increase its gathering and treating capacity by an additional 200 MMcf per day, increasing the aggregate capacity of the system to 900 MMcf per day. The expansion was completed and placed into service in February 2011 at a total cost of approximately $52 million. The 200 MMcf per day incremental volume commitment made by Shell and Encana began contemporaneously with the completion of the expansion.

Under the long-term agreements, Encana or Shell may elect to require CEFS to expand the capacity of the Magnolia Gathering System by up to an additional 800 MMcf per day, bringing the total system capacity to 1.7 Bcf per day.  CEFS estimates that the cost to expand the capacity of the Magnolia Gathering System by an additional 800 MMcf per day would be as much as $240 million.  Encana and Shell would provide incremental volume commitments in connection with an election to expand the system’s capacity.

Olympia Gathering System.  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 certain Haynesville Shale and Bossier Shale formations in Texas and Louisiana. Pursuant to these agreements, CEFS acquired jointly-owned gathering facilities (the Olympia Gathering System) from Encana and Shell in northwest Louisiana.

Under the terms of the agreements, CEFS is expanding the Olympia Gathering System in order to permit the system to gather and treat up to 600 MMcf per day of natural gas. As of June 30, 2011, CEFS had spent approximately $375 million on the 600 MMcf per day project, including the purchase of the original facilities, and expects to incur up to an additional $50 million to complete the remaining contractual milestones and well connects for this expansion.  CEFS is in the second year of the 10-year, 600 MMcf per day volume commitment made by Shell and Encana which commenced in April 2010.

Under the long-term agreements, Encana and Shell may elect to require CEFS to expand the capacity of the Olympia Gathering System by up to an additional 520 MMcf per day, bringing the total system capacity to 1.1 Bcf per day.  CEFS estimates that the cost to expand the capacity of the Olympia Gathering System by an additional 520 MMcf per day would be as much as $200 million. Encana and Shell would provide incremental volume commitments in connection with an election to expand the system’s capacity.

(c) Legal, Environmental and Other Regulatory Matters

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 certain lawsuits described below.  Under a master separation agreement between CenterPoint Energy and a former subsidiary, RRI Energy, Inc. (RRI), CenterPoint Energy and its subsidiaries are entitled to be indemnified by RRI and its successors for any losses,

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including attorneys’ fees and other costs, arising out of these lawsuits.  In May 2009, RRI sold its Texas retail business to NRG Retail LLC, a subsidiary of NRG Energy, Inc. and changed its name to RRI Energy, Inc. In December 2010, Mirant Corporation merged with and became a wholly owned subsidiary of RRI Energy, Inc., and RRI Energy, Inc. changed its name to GenOn Energy, Inc. (GenOn). Neither the sale of the retail business nor the merger with Mirant Corporation alters RRI’s (now GenOn’s) contractual obligations to indemnify CenterPoint Energy and its subsidiaries for certain liabilities, including their indemnification obligations regarding the gas market manipulation litigation, nor does it affect the terms of existing guaranty arrangements for certain GenOn gas transportation contracts discussed below.

A large number of lawsuits were filed against numerous gas market participants in a number of federal and western state courts in connection with the operation of the natural gas markets in 2000-2002. CenterPoint Energy’s former affiliate, RRI, was a participant in gas trading in the California and Western markets. These lawsuits, many of which have been filed as class actions, allege violations of state and federal antitrust laws. Plaintiffs in these lawsuits are seeking a variety of forms of relief, including, among others, recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages, full consideration damages and attorneys’ fees. CenterPoint Energy and/or Reliant Energy were named in approximately 30 of these lawsuits, which were instituted between 2003 and 2009. CenterPoint Energy and its affiliates have been released or dismissed from all but two of such cases. CenterPoint Energy Services, Inc. (CES), a subsidiary of CERC Corp., is a defendant in a case now pending in federal court in Nevada alleging a conspiracy to inflate Wisconsin natural gas prices in 2000-2002.  In July 2011, the court issued an order dismissing the plaintiffs’ claims against the other defendants in the case, each of whom had demonstrated FERC jurisdictional sales for resale during the relevant period, based on federal preemption. 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. CenterPoint Energy believes that neither it nor CES is a proper defendant in these remaining cases and will continue to pursue dismissal from those cases.  CenterPoint Energy 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.

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 CERC Corp. subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the British thermal unit (Btu) content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a putative class of royalty owners in which they assert their claims that the defendants have engaged in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees.  In September 2009, the district court in Stevens County, Kansas, denied plaintiffs’ request for class certification of their case and, in March 2010, denied the plaintiffs’ request for reconsideration of that order. The time for seeking further review of the district court’s decision has now passed.

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, 2011, CERC had accrued $13 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

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similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRPs), if any, and the remediation methods used. The Minnesota Public Utility Commission has provided for the inclusion in rates of approximately $285,000 annually to fund normal on-going remediation costs.  As of June 30, 2011, CERC had collected $5.3 million from insurance companies to be used for future environmental remediation.

In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CERC has been named as a defendant in a lawsuit filed in the United States District Court, District of Maine, under which contribution is sought by private parties for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of CERC or its divisions. CERC has also been identified as a PRP by the State of Maine for a site that is a 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 potentially 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 and, in July 2011, the plaintiff appealed the federal district court’s decision to the United States Court of Appeals for the First Circuit.  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.

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.

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 (now GenOn) 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 based on an annual calculation, with any required collateral to be posted each December.  The undiscounted maximum potential payout of the demand charges under these transportation contracts, which will be in effect until 2018, was approximately $105 million as of June 30, 2011. Market conditions in the fourth quarter of 2010 required posting of security under the agreement, and GenOn posted approximately

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$7 million in collateral in December 2010.  If GenOn 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, 2010, the effective tax rate was 41% and 46%, respectively.  During the three and six months ended June 30, 2011, the effective tax rate was 40% and 39%, respectively.  The comparability of the effective tax rate for the six months ended June 30, 2010 and 2011 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 $22 million in March 2010.  The portion of the reduction that CERC believes will be recovered through the regulatory process, or approximately $2 million, was recorded as an adjustment to regulatory assets.  The regulatory assets were also increased in March 2010 by approximately $1 million related to the recovery of CERC’s income taxes.  The remaining $19 million of the reduction in CERC’s deferred tax asset was recorded as a charge to income tax expense in the first quarter of 2010.

The following table summarizes CERC’s unrecognized tax benefits at December 31, 2010 and June 30, 2011:

	December 31, 2010			June 30, 2011
	(in millions)
Unrecognized tax benefits	$	11		$	9
Portion of unrecognized tax benefits that, if recognized, would reduce the effective income tax rate		5			5
Interest accrued on unrecognized tax benefits		(5	)		(4	)

It is reasonably possible that the total amount of unrecognized tax benefits could decrease by as much as $1 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, the conclusion of which would result in the final disposition of an uncontested adjustment proposed by the IRS relating to the capitalization into inventory of certain direct and indirect expenses incurred by CERC.  It is also reasonably possible that the total amount of unrecognized tax benefits could increase by as much as $18 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.  Additionally, the capitalization of expenses into inventory and the deduction for debt issuance costs are temporary differences and, therefore, any increase or decrease in the balance of unrecognized tax benefits related thereto would not affect the effective tax rate.

In January 2011, the IRS commenced its examination of CenterPoint Energy’s 2008 and 2009 consolidated federal income tax returns, of which CERC is a member.

(13)           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.  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

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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, 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 Three Months Ended June 30, 2011
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)
Natural Gas Distribution	$	448	$	4		$	13
Competitive Natural Gas Sales and Services		581		5			3
Interstate Pipelines		111		31			60
Field Services		88		10			39
Other Operations		—		—			(1	)
Eliminations		—		(50	)		—
Consolidated	$	1,228	$	—		$	114

	For the Six Months Ended June 30, 2010
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2010
Natural Gas Distribution	$	1,995	$	7		$	149		$	4,575
Competitive Natural Gas Sales and Services		1,394		18			9			1,190
Interstate Pipelines		216		70			139			3,672
Field Services		124		24			54			1,803
Other Operations		—		—			(2	)		659
Eliminations		—		(119	)		—			(1,361	)
Consolidated	$	3,729	$	—		$	349		$	10,538

	For the Six Months Ended June 30, 2011
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)			Total Assets as of June 30, 2011
Natural Gas Distribution	$	1,655	$	9		$	155		$	4,438
Competitive Natural Gas Sales and Services		1,278		14			13			1,110
Interstate Pipelines		224		65			136			3,766
Field Services		166		22			75			1,832
Other Operations		—		—			(5	)		545
Eliminations		—		(110	)		—			(1,596	)
Consolidated	$	3,323	$	—		$	374		$	10,095

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(14)           Other Current Assets and Liabilities

Included in other current assets on the Condensed Consolidated Balance Sheets at December 31, 2010 and June 30, 2011 was $23 million and $18 million, respectively, of margin deposits and $99 million and $66 million, respectively, of under-recovered gas cost. Included in other current liabilities on the Condensed Consolidated Balance Sheets at December 31, 2010 and June 30, 2011 was $94 million and $48 million, respectively, of over-recovered gas cost.

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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, 2010 (2010 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, 2010 and the three and six months ended June 30, 2011.  Reference is made to “Management’s Narrative Analysis of Results of Operations” in Item 7 of our 2010 Form 10-K.

EXECUTIVE SUMMARY

Recent Events

Olympia Gathering System

In April 2010, CenterPoint Energy Field Services, LLC (CEFS) 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 Texas and Louisiana. Pursuant to these agreements, CEFS acquired jointly-owned gathering facilities (the Olympia Gathering System) from Encana and Shell in northwest Louisiana.

Under the terms of the agreements, CEFS is expanding the Olympia Gathering System in order to permit the system to gather and treat up to 600 MMcf per day of natural gas. As of June 30, 2011, CEFS had spent approximately $375 million on the 600 MMcf per day project, including the purchase of the original facilities, and expects to incur up to an additional $50 million to complete the remaining contractual milestones and well connects for this expansion.  CEFS is in the second year of the 10-year, 600 MMcf per day volume commitment made by Shell and Encana which commenced in April 2010.

Under the long-term agreements, Encana and Shell may elect to require CEFS to expand the capacity of the Olympia Gathering System by up to an additional 520 MMcf per day, bringing the total system capacity to 1.1 Bcf per day.  CEFS estimates that the cost to expand the capacity of the Olympia Gathering System by an additional 520 MMcf per day would be as much as $200 million. Encana and Shell would provide incremental volume commitments in connection with an election to expand the system’s capacity.

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), the Commodities Futures Trading Commission (CFTC) 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 CFTC.

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Dodd-Frank also makes substantial changes to the regulatory oversight of the credit rating agencies that are typically engaged to rate our securities. 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, the effectiveness of our risk management activities, debt service costs and income tax expense.  For more information regarding factors that may affect the future results of operations of our business, please read “Risk Factors” in Item 1A of Part I of our 2010 Form 10-K.

The following table sets forth our consolidated results of operations for the three and six months ended June 30, 2010 and 2011, followed by a discussion of our consolidated results of operations.

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2011			2010			2011
	(in millions)
Revenues	$	1,191		$	1,228		$	3,729		$	3,323
Expenses:
Natural gas		778			778			2,713			2,254
Operation and maintenance		214			237			446			477
Depreciation and amortization		63			65			123			131
Taxes other than income taxes		35			34			98			87
Total Expenses		1,090			1,114			3,380			2,949
Operating Income		101			114			349			374
Interest and Other Finance Charges		(52	)		(45	)		(103	)		(94	)
Equity in earnings of unconsolidated affiliates		7			8			12			14
Other Income, net		—			1			—			2
Income Before Income Taxes		56			78			258			296
Income Tax Expense		23			31			119			116
Net Income	$	33		$	47		$	139		$	180

Three months ended June 30, 2011 compared to three months ended June 30, 2010

We reported net income of $47 million for the three months ended June 30, 2011 compared to $33 million for the same period in 2010.  The increase in net income of $14 million was primarily due to a $13 million increase in operating income from our business segments as discussed below, a $7 million decrease in interest and other finance charges, partially offset by an $8 million increase in income tax expense.

Six months ended June 30, 2011 compared to six months ended June 30, 2010

We reported net income of $180 million for the six months ended June 30, 2011 compared to $139 million for the same period in 2010.  The increase in net income of $41 million was primarily due to a $25 million increase in operating income from our business segments as discussed below, a $9 million decrease in interest and other finance charges and a $3 million decrease in income tax expense.

Income Tax Expense.During the three and six months ended June 30, 2010, our effective tax rate was 41% and 46%, respectively.  During the three and six months ended June 30, 2011, our effective tax rate was 40% and 39%, respectively.  The comparability of our effective tax rate for the six months ended June 30, 2010 and 2011 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,

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we reduced our deferred tax asset by approximately $22 million in March 2010.  The portion of the reduction that we believe will be recovered through the regulatory process, or approximately $2 million, was recorded as an adjustment to regulatory assets.  The regulatory assets were also increased in March 2010 by approximately $1 million related to the recovery of our income taxes.  The remaining $19 million of the reduction in our deferred tax asset was recorded as a charge to income tax expense in the first quarter of 2010.

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, 2010 and 2011, 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,
	2010			2011			2010			2011
	(in millions)
Natural Gas Distribution	$	10		$	13		$	149		$	155
Competitive Natural Gas Sales and Services		(6	)		3			9			13
Interstate Pipelines		67			60			139			136
Field Services		31			39			54			75
Other Operations		(1	)		(1	)		(2	)		(5	)
Total Consolidated Operating Income	$	101		$	114		$	349		$	374

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 I of our 2010 Form 10-K.

The following table provides summary data of our Natural Gas Distribution business segment for the three and six months ended June 30, 2010 and 2011 (in millions, except throughput and customer data):

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2011		2010		2011
Revenues	$	465	$	452	$	2,002	$	1,664
Expenses:
Natural gas		244		218		1,383		1,036
Operation and maintenance		144		157		311		325
Depreciation and amortization		44		41		84		83
Taxes other than income taxes		23		23		75		65
Total expenses		455		439		1,853		1,509
Operating Income	$	10	$	13	$	149	$	155
Throughput (in Bcf):
Residential		16		20		112		110
Commercial and industrial		49		51		136		139
Total Throughput		65		71		248		249
Number of customers at period end:
Residential		2,973,013		3,000,665		2,973,013		3,000,665
Commercial and industrial		244,089		243,629		244,089		243,629
Total		3,217,102		3,244,294		3,217,102		3,244,294

Three months ended June 30, 2011 compared to three months ended June 30, 2010

Our Natural Gas Distribution business segment reported operating income of $13 million for the three months ended June 30, 2011 compared to $10 million for the three months ended June 30, 2010.  Operating income increased $3 million primarily as a result of increased volumetric revenue including the revenue impacts of weather

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partially mitigated by weather hedges and weather normalization adjustments ($7 million) and increased throughput to large-volume customers ($2 million). The increase is partially offset by increased operation and maintenance expenses ($3 million).  Increased operation and maintenance expenses related to energy efficiency programs ($10 million) were offset by the related revenues.

Six months ended June 30, 2011 compared to six months ended June 30, 2010

Our Natural Gas Distribution business segment reported operating income of $155 million for the six months ended June 30, 2011 compared to operating income of $149 million for the six months ended June 30, 2010.  Operating income increased $6 million primarily as a result of increased throughput to large-volume customers ($5 million) and the effect of adding 27,000 residential customers ($2 million).  Increased operation and maintenance expenses related to energy efficiency programs ($15 million) were offset by the related revenues.

Competitive Natural Gas Sales and Services

For information regarding factors that may affect the future results of operations of our Competitive Natural Gas Sales and Services business segment, please read "Risk Factors ─ Risk Factors Affecting Our Businesses," "─ Risk Factors Associated with Our Consolidated Financial Condition" and "─ Other Risks" in Item 1A of Part I of our 2010 Form 10-K.

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, 2010 and 2011 (in millions, except throughput and customer data):

	Three Months Ended June 30,					Six Months Ended June 30,
	2010			2011		2010		2011
Revenues	$	560		$	586	$	1,412	$	1,292
Expenses:
Natural gas		554			571		1,380		1,256
Operation and maintenance		10			11		19		21
Depreciation and amortization		1			1		2		2
Taxes other than income taxes		1			—		2		—
Total expenses		566			583		1,403		1,279
Operating Income (Loss)	$	(6	)	$	3	$	9	$	13
Throughput (in Bcf)		128			126		269		281
Number of customers at period end		11,694			12,152		11,694		12,152

Three months ended June 30, 2011 compared to three months ended June 30, 2010

Our Competitive Natural Gas Sales and Services business segment reported operating income of $3 million for the three months ended June 30, 2011 compared to operating loss of $6 million for the three months ended June 30, 2010.  The increase in operating income of $9 million is primarily due to the favorable impact of the mark-to-market valuation for non-trading financial derivatives for the three months ended June 30, 2011 of $4 million compared to an unfavorable impact of $8 million for the same period in 2010.  The segment’s retail business experienced greater throughput volumes and increased the number of customers in the second quarter of 2011 compared to the second quarter of 2010 resulting in increased operating income of $1 million.  Offsetting these increases to operating income was a $5 million quarter-over-quarter decrease in margin resulting mainly from reduced basis spreads on pipeline transport opportunities.

Six months ended June 30, 2011 compared to six months ended June 30, 2010

Our Competitive Natural Gas Sales and Services business segment reported operating income of $13 million for the six months ended June 30, 2011 compared to $9 million for the six months ended June 30, 2010. The increase in operating income of $4 million is primarily due to the favorable impact of the mark-to-market valuation for non-trading financial derivatives for the first six months of 2011 of $2 million compared to an unfavorable impact of $5 million for the same period in 2010.  Offsetting this increase was a $6 million year-over-year decrease in operating income resulting from reduced basis spreads on pipeline transport opportunities and lack of seasonal

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storage spreads.  The segment’s retail business experienced greater throughput volumes and increased the number of customers in the first half of 2011 resulting in an operating income increase of $1 million compared to the first half of 2010.

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 I of our 2010 Form 10-K.

The following table provides summary data of our Interstate Pipelines business segment for the three and six months ended June 30, 2010 and 2011 (in millions, except throughput data):

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2011		2010		2011
Revenues	$	148	$	142	$	286	$	289
Expenses:
Natural gas		24		21		34		39
Operation and maintenance		35		39		70		70
Depreciation and amortization		13		14		26		27
Taxes other than income taxes		9		8		17		17
Total expenses		81		82		147		153
Operating Income	$	67	$	60	$	139	$	136
Equity in earnings of unconsolidated affiliates	$	4	$	5	$	7	$	9
Transportation throughput (in Bcf)		400		396		838		852

Three months ended June 30, 2011 compared to three months ended June 30, 2010

Our Interstate Pipeline business segment reported operating income of $60 million for the three months ended June 30, 2011 compared to $67 million for the three months ended June 30, 2010.  Margins (revenues less natural gas costs) decreased $3 million primarily due to an expiring backhaul contract ($5 million), lower off-system transportation sales ($2 million) and the effects of the restructured 10-year agreement with our natural gas distribution affiliate ($3 million), which were partially offset by increased ancillary services ($7 million).  We estimate that the expiration of the backhaul contract will adversely impact our 2011 revenues by approximately $20 million. Increased operation and maintenance expenses ($4 million) and increased depreciation and amortization expense ($1 million) were partially offset by lower taxes other than income ($1 million).

Equity Earnings.  In addition, this business segment recorded equity income of $4 million and $5 million for the three months ended June 30, 2010 and 2011, respectively, from its 50% interest in the Southeast Supply Header (SESH), a jointly-owned pipeline.  These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Six months ended June 30, 2011 compared to six months ended June 30, 2010

Our Interstate Pipeline business segment reported operating income of $136 million for the six months ended June 30, 2011 compared to $139 million for the six months ended June 30, 2010. Margins (revenues less natural gas costs) decreased $2 million primarily due to the effects of the restructured 10-year agreement with our natural gas distribution affiliate ($4 million), lower off-system sales ($2 million) and lower revenues ($1 million) related to an expiring backhaul contract, partially offset by new firm transportation contract revenues.  Partially offsetting these declines were increased margins from ancillary service ($2 million), new power plant transportation contracts ($2 million) and industrial customers ($1 million).  Increased operation and maintenance expenses were offset by a favorable insurance settlement related to a damaged compressor station ($4 million) recognized in the first quarter of 2011.  Depreciation expense increased ($1 million) due to asset additions.

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Equity Earnings.  In addition, this business segment recorded equity income of $7 million and $9 million for the six months ended June 30, 2010 and 2011, respectively, from its 50% interest in SESH.  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 I of our 2010 Form 10-K.

The following table provides summary data of our Field Services business segment for the three and six months ended June 30, 2010 and 2011 (in millions, except throughput data):

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2011		2010		2011
Revenues	$	80	$	98	$	148	$	188
Expenses:
Natural gas		18		18		34		33
Operation and maintenance		25		29		46		58
Depreciation and amortization		5		10		11		19
Taxes other than income taxes		1		2		3		3
Total expenses		49		59		94		113
Operating Income	$	31	$	39	$	54	$	75
Equity in earnings of unconsolidated affiliates	$	3	$	3	$	5	$	5
Gathering throughput (in Bcf)		156		197		284		380

Three months ended June 30, 2011 compared to three months ended June 30, 2010

Our Field Services business segment reported operating income of $39 million for the three months ended June 30, 2011 compared to $31 million for the three months ended June 30, 2010.  Margins increased primarily from new projects and core gathering services ($23 million) partially offset by lower prices received from sales of retained natural gas ($4 million). Increases in operation and maintenance expense ($4 million) and depreciation and amortization expense ($5 million) are due to the expansion of the facilities for the Magnolia and Olympia gathering systems in north Louisiana.

Equity Earnings.  In addition, this business segment recorded equity income of $3 million in both the three months ended June 30, 2010 and 2011, from its 50% general partnership interest in Waskom Gas Processing Company (Waskom).  These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Six months ended June 30, 2011 compared to six months ended June 30, 2010

Our Field Services business segment reported operating income of $75 million for the six months ended June 30, 2011 compared to $54 million for the six months ended June 30, 2010. Increased margins primarily from new projects and core gathering services ($49 million) were partially offset by lower prices received from sales of retained natural gas ($7 million) and processing margins ($1 million). Increases in operation and maintenance expense ($12 million) and depreciation and amortization expense ($8 million) are due to the expansion of the facilities for the Magnolia and Olympia gathering systems in north Louisiana.

Equity Earnings.  In addition, this business segment recorded equity income of $5 million in both the six months ended June 30, 2010 and 2011, from its 50% general partnership interest in Waskom.  These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

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CERTAIN FACTORS AFFECTING FUTURE EARNINGS

For information on other developments, factors and trends that may have an impact on our future earnings, please read “Management’s Narrative Analysis of Results of Operations — Certain Factors Affecting Future Earnings” in Item 7 of Part II of our 2010 Form 10-K, “Risk Factors” in Item 1A of Part I of our 2010 Form 10-K and “Cautionary Statement Regarding Forward-Looking Information” in this Form 10-Q.

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 regulatory actions. Substantially all of our capital expenditures are expected to be used for investment in infrastructure for our natural gas transmission, distribution and gathering operations. These capital expenditures are anticipated to both maintain reliability and safety as well as to expand our systems through value-added projects. Our principal anticipated cash requirements for the remaining six months of 2011 include approximately $425 million of capital expenditures.

We expect that proceeds from sales of commercial paper, borrowings under our credit facility, anticipated cash flows from operations and borrowings from affiliates will be sufficient to meet our anticipated cash needs for the remaining six months of 2011.  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 the guaranties described below and operating leases, we have no off-balance sheet arrangements.

Prior to CenterPoint Energy’s distribution of its ownership in RRI Energy, 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 (now named GenOn Energy, Inc. (GenOn)) 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 based on an annual calculation, with any required collateral to be posted each December.  The undiscounted maximum potential payout of the demand charges under these transportation contracts, which will be in effect until 2018, was approximately $105 million as of June 30, 2011.  Market conditions in the fourth quarter of 2010 required posting of security under the agreement, and GenOn posted approximately $7 million in collateral in December 2010. If GenOn 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.

Debt Financing Transactions.  In January 2011, we issued $250 million aggregate principal amount of senior notes due 2021 with an interest rate of 4.50% and $300 million aggregate principal amount of senior notes due 2041 with an interest rate of 5.85%.  The proceeds from the issuance of the notes were used for the repayment of $550 million of our 7.75% senior notes at their maturity in February 2011.

Also in January 2011, we issued an additional $343 million aggregate principal amount of 4.50% senior notes due 2021 and provided cash consideration of $114 million in exchange for $397 million aggregate principal amount of our 7.875% senior notes due 2013.  The premium of $58 million paid on exchanged notes has been deferred and will be amortized to interest expense over the life of the 4.50% senior notes due 2021.

Credit and Receivables Facilities.  As of July 15, 2011, we had the following facilities (in millions):

Date Executed	Type of Facility	Size of Facility		Amount Utilized at July 15, 2011			Termination Date
June 29, 2007	Revolver	$	915	$	58	(1)	June 29, 2012
September 15, 2010	Receivables		240		—		September 14, 2011

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(1) Represents commercial paper that is backstopped by CERC Corp.’s revolving credit facility.

In the third quarter of 2011, we expect to replace our credit facility that terminates in 2012 with a new five-year credit facility having a similar borrowing capacity.

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, limiting debt to 65% of our total capitalization.

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 of June 30, 2011, CERC Corp. had $70 million of outstanding commercial paper. 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.

During the second quarter of 2011, we met a portion of our liquidity requirements with commercial paper proceeds.  We currently expect that we may be required to continue to access financing sources, in addition to money pool borrowings, in order to satisfy our liquidity requirements in 2011.  These sources could include commercial paper proceeds or borrowings under CERC Corp.’s revolving credit facility.

Securities Registered with the SEC.  We have registered an indeterminate principal amount of our senior debt securities under a joint registration statement with CenterPoint Energy and CenterPoint Energy Houston Electric, LLC.

Temporary Investments.  As of July 15, 2011, 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 15, 2011, we had borrowings of $404 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 rating. As of July 15, 2011, Moody’s Investors Service, Inc. (Moody’s), Standard & Poor’s Ratings Services, a division of The McGraw Hill Companies (S&P), and Fitch, Inc. (Fitch) had assigned the following credit ratings to our senior unsecured debt:

Moody’s		S&P		Fitch
Rating	Outlook (1)	Rating	Outlook (2)	Rating	Outlook (3)
Baa2	Stable	BBB	Positive	BBB	Stable

(1) A Moody’s rating outlook is an opinion regarding the likely direction of an issuer’s 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.

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(3) A Fitch rating outlook 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, 2011, 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, 2011, the amount posted as collateral aggregated approximately $59 million ($31 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, 2011, unsecured credit limits extended to CES by counterparties aggregate $281 million; however, utilized credit capacity was $48 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, CERC Corp. might need to provide cash or other collateral of as much as $179 million as of June 30, 2011. 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, three outstanding series of CenterPoint Energy’s senior notes, aggregating $750 million in principal amount as of June 30, 2011, 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, revolving credit facility or receivables facility.

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 action in this regard will be based on market conditions and

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opportunities existing at the time, and accordingly, the timing, size or success of any efforts and the associated potential capital commitments are unpredictable. We may seek to fund all or part of any such efforts with proceeds from debt issuances. Debt financing may not, however, be available to us at that time due to a variety of events, including, among others, maintenance of our credit ratings, industry conditions, general economic conditions, market conditions and market perceptions.

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

• cash collateral requirements that could exist in connection with certain contracts, including 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;

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

• increased costs related to the acquisition of natural gas;

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

• various legislative or regulatory actions;

• 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 GenOn and its subsidiaries to satisfy their obligations in respect of GenOn’s indemnity obligations to CenterPoint Energy and its 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

• various other risks identified in “Risk Factors” in Item 1A of our 2010 Form 10-K.

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. 

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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, 2011 to provide assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.

There has been no change in our internal controls over financial reporting that occurred during the three months ended June 30, 2011 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(c) 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 2010 Form 10-K.

Item 1A.  RISK FACTORS

There have been no material changes from the risk factors disclosed in our 2010 Form 10-K.

Item 5.     OTHER INFORMATION

Our ratio of earnings to fixed charges for the six months ended June 30, 2010 and 2011 was 3.24 and 3.87, 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)

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Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
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
+101.INS	XBRL Instance Document (1)
+101.SCH	XBRL Taxonomy Extension Schema Document (1)
+101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document (1)
+101.LAB	XBRL Taxonomy Extension Labels Linkbase Document (1)
+101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document (1)

(1)           Furnished, not filed.

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SIGNATURES

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

	CENTERPOINT ENERGY RESOURCES CORP.
By:	/s/ Walter L. Fitzgerald
	Walter L. Fitzgerald
	Senior Vice President and Chief Accounting Officer

Date:  August 10, 2011

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Index to Exhibits

The following exhibits are filed herewith:

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

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
+101.INS	XBRL Instance Document (1)
+101.SCH	XBRL Taxonomy Extension Schema Document (1)
+101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document (1)

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Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
+101.LAB	XBRL Taxonomy Extension Labels Linkbase Document (1)
+101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document (1)

(1)           Furnished, not filed.

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