View Filing Data

Document And Entity Information - USD ($)	9 Months Ended
Document And Entity Information - USD ($)	Sep. 30, 2011	Oct. 14, 2011	Jun. 30, 2010
Entity Registrant Name	CENTERPOINT ENERGY RESOURCES CORP
Entity Central Index Key	0001042773
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float			$ 0
Entity Common Stock, Shares Outstanding		1,000
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011

CONDENSED STATEMENTS OF CONSOLIDATED INCOME (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Condensed Statements of Consolidated Income (Unaudited) [Abstract]
Revenues	$ 1,171	$ 1,250	$ 4,494	$ 4,979
Expenses:
Natural gas	735	808	2,989	3,521
Operation and maintenance	227	238	704	684
Depreciation and amortization	65	61	196	184
Taxes other than income taxes	33	32	120	130
Total	1,060	1,139	4,009	4,519
Operating Income	111	111	485	460
Other Income (Expense):
Interest and other finance charges	(48)	(52)	(142)	(155)
Equity in earnings of unconsolidated affiliates	8	10	22	22
Other, net	(1)	(1)	1	(1)
Total	(41)	(43)	(119)	(134)
Income Before Income Taxes	70	68	366	326
Income tax expense	27	26	143	145
Net Income	$ 43	$ 42	$ 223	$ 181

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Sep. 30, 2011	Dec. 31, 2010
Current Assets:
Cash and cash equivalents	$ 0	$ 1
Accounts and notes receivable, net	415	603
Accrued unbilled revenue	81	270
Accounts and notes receivable - affiliated companies	14	19
Materials and supplies	93	93
Natural gas inventory	250	211
Non-trading derivative assets	52	54
Taxes receivable	2	63
Deferred tax asset	33	48
Prepaid expenses and other current assets	117	208
Total current assets	1,057	1,570
Property, Plant and Equipment:
Property, plant and equipment	8,356	7,939
Less accumulated depreciation and amortization	1,450	1,303
Property, plant and equipment, net	6,906	6,636
Other Assets:
Goodwill	1,696	1,696
Non-trading derivative assets	12	15
Investment in unconsolidated affiliates	474	468
Other	132	153
Total other assets	2,314	2,332
Total Assets	10,277	10,538
Current Liabilities:
Short-term borrowings	84	53
Accounts payable	318	573
Accounts and notes payable - affiliated companies	443	541
Taxes accrued	90	73
Interest accrued	56	51
Customer deposits	75	76
Non-trading derivative liabilities	53	68
Other	127	255
Total current liabilities	1,246	1,690
Other Liabilities:
Accumulated deferred income taxes, net	1,407	1,319
Non-trading derivative liabilities	3	16
Benefit obligations	100	100
Regulatory liabilities	604	572
Other	143	140
Total other liabilities	2,257	2,147
Long-term Debt	2,775	2,925
Commitments and Contingencies (Note 11)
Stockholder's Equity:
Common stock	0	0
Paid-in capital	2,416	2,416
Retained earnings	1,588	1,365
Accumulated other comprehensive loss	(5)	(5)
Total stockholder's equity	3,999	3,776
Total Liabilities and Stockholder's Equity	$ 10,277	$ 10,538

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Cash Flows from Operating Activities:
Net income	$ 223	$ 181
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	196	184
Amortization of deferred financing costs	10	7
Deferred income taxes	102	118
Write-down of natural gas inventory	7	6
Equity in earnings of unconsolidated affiliates, net of distributions	3	4
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net.	356	515
Accounts receivable/payable, affiliates	(12)	(17)
Inventory	(46)	(85)
Taxes receivable	61	(53)
Accounts payable	(218)	(276)
Fuel cost over (under) recovery	(52)	43
Interest and taxes accrued	22	30
Non-trading derivatives, net	(8)	(15)
Margin deposits, net.	61	(38)
Other current assets	18	(5)
Other current liabilities	(33)	(38)
Other assets	5	(2)
Other liabilities	3	(14)
Other, net	2	0
Net cash provided by operating activities	700	545
Cash Flows from Investing Activities:
Capital expenditures	(483)	(652)
Investment in unconsolidated affiliates	(9)	(21)
Other, net	10	(3)
Net cash used in investing activities	(482)	(676)
Cash Flows from Financing Activities:
Increase in short-term borrowings, net	31	18
Proceeds from commercial paper, net	(41)	0
Proceeds from long-term debt	550	0
Payments of long-term debt	(606)	(45)
Cash paid for debt exchange	(58)	0
Debt issuance costs	(14)	0
Increase (decrease) in notes payable to affiliates	(81)	158
Net cash provided by (used in) financing activities	(219)	131
Net Decrease in Cash and Cash Equivalents	(1)	0
Cash and Cash Equivalents at Beginning of Period	1	1
Cash and Cash Equivalents at End of Period	0	1
Cash Payments:
Interest, net of capitalized interest	123	127
Income taxes (refunds), net	(18)	80
Non-cash transactions:
Accounts payable related to capital expenditures	$ 61	$ 62

Background and Basis of Presentation	9 Months Ended
Background and Basis of Presentation	Sep. 30, 2011
Background and Basis of Presentation [Abstract]
Background and Basis of Presentation	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.

- Definition

The entire disclosure for organization, consolidation and basis of presentation of financial statements disclosure.

+ References

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+ Details

New Accounting Pronouncements	9 Months Ended
New Accounting Pronouncements	Sep. 30, 2011
New Accounting Pronouncements [Abstract]
New Accounting Pronouncements	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 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. In September 2011, the FASB issued new accounting guidance that is intended to simplify how entities test goodwill for impairment. The new accounting guidance permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If, after performing the qualitative assessment, it is determined that the fair value of a reporting unit is more likely than not less than its carrying value, then the quantitative two-step goodwill impairment test that exists under current GAAP must be performed; otherwise, goodwill is deemed to not be impaired and no further testing is required. An entity has the unconditional option to bypass the qualitative assessment and proceed directly to the quantitative assessment. This new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011, with early adoption permitted. CERC did not elect early adoption, but 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.

- Definition

Tabular disclosure of changes in accounting principles, including adoption of new accounting pronouncements, that describes the new methods, amount and effects on financial statement line items.

+ References

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+ Details

Employee Benefit Plans

9 Months Ended

Sep. 30, 2011

Employee Benefit Plans [Abstract]

Employee Benefit Plans

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2011			2010			2011
	(in millions)
Interest cost	$	2		$	1		$	5		$	4
Expected return on plan assets		(1	)		(1	)		(1	)		(1	)
Amortization of prior service cost		1			1			2			2
Amortization of net loss		-			1			-			1
Net periodic cost	$	2		$	2		$	6		$	6

CERC expects to contribute approximately $8 million to its postretirement benefit plan in 2011, of which $-0- and $6 million, respectively, was contributed during the three and nine months ended September 30, 2011.

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References

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+ Details

Regulatory Matters	9 Months Ended
Regulatory Matters	Sep. 30, 2011
Regulatory Matters [Abstract]
Regulatory Matters	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 appealed the court's ruling on the cost of service adjustment mechanism to the Texas Third Court of Appeals in Austin, Texas. Oral arguments were held in February 2011. In October 2011, the Texas Third Court of Appeals reversed the district court's ruling. Parties opposed to the decision may request the Texas Third Court of Appeals to reconsider or appeal to the Texas Supreme Court. 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, which request was granted in July 2011. In July 2009, Gas Operations filed a request to change its rates with the Railroad Commission and the 29 cities in its Houston service territory, consisting of approximately 940,000 customers in and around Houston. The request sought to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Houston service territory. As finally submitted to the Railroad Commission and the cities, the proposed new rates would have resulted in an overall increase in annual revenue of $20.4 million, excluding carrying costs of approximately $2 million on its gas inventory. In 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 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.

Derivative Instruments

9 Months Ended

Sep. 30, 2011

Derivative Instruments [Abstract]

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 and does not engage in proprietary or speculative commodity trading. These financial instruments do not qualify or are not designated as cash flow or fair value hedges.

During the three months ended September 30, 2010, CERC recorded increased natural gas revenues from unrealized net gains of $28 million and increased natural gas expense from unrealized net losses of $9 million, resulting in a net unrealized gain of $19 million. During the three months ended September 30, 2011, CERC recorded increased natural gas revenues from unrealized net gains of $18 million and increased natural gas expense from unrealized net losses of $12 million, resulting in a net unrealized gain of $6 million. During the nine months ended September 30, 2010, CERC recorded increased natural gas revenues from unrealized net gains of $45 million and increased natural gas expense from unrealized net losses of $31 million, resulting in a net unrealized gain of $14 million. During the nine months ended September 30, 2011, CERC recorded decreased natural gas revenues from unrealized net losses of $1 million and decreased natural gas expense from unrealized net gains of $9 million, resulting in a net unrealized gain of $8 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 nine months ended September 30, 2010, CERC recognized losses of $-0- and $1 million, respectively, related to these swaps. During the three and nine months ended September 30, 2011, CERC recognized losses of $-0- 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 September 30, 2011, while the last table provides a breakdown of the related income statement impacts for the three and nine months ended September 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 constitute 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.

Fair Value of Derivative Instruments
		September 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	$	52	$	-
Natural gas contracts (1)	Other Assets		12		-
Natural gas contracts (1)	Current Liabilities		22		104
Natural gas contracts (1)	Other Liabilities		1		7
Total		$	87	$	111

(1)

(2)

The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 585 Bcf or a net 69 Bcf long position. Of the net long position, basis swaps constitute 69 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment constitute 10 Bcf.

(3)

The net of total non-trading derivative assets and liabilities is an $8 million asset as shown on CenterPoint Energy'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 $32 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 September 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2010			2011
		(in millions)
Natural gas contracts	Gains (Losses) in Revenue	$	41		$	27
Natural gas contracts (1)	Gains (Losses) in Expense: Natural Gas		(41	)		(30	)
Total		$	-		$	(3	)

(1)

The Gains (Losses) in Expense: Natural Gas includes $(24) 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
		Nine Months Ended September 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2010			2011
		(in millions)
Natural gas contracts	Gains (Losses) in Revenue	$	90		$	41
Natural gas contracts (1)	Gains (Losses) in Expense: Natural Gas		(133	)		(79	)
Total		$	(43	)	$	(38	)

(1)

The Gains (Losses) in Expense: Natural Gas includes $(74) million and $(79) 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.

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 September 30, 2011 was $107 million and $51 million, respectively. The aggregate fair value of assets that are already posted as collateral was $31 million and $2 million, respectively, at December 31, 2010 and September 30, 2011. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at December 31, 2010 and September 30, 2011, $76 million and $48 million, respectively, of additional assets would be required to be posted as collateral.

- Definition

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Financial Accounting Standard (FAS)
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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+ Details

Fair Value Measurements

9 Months Ended

Sep. 30, 2011

Fair Value Measurements [Abstract]

Fair Value Measurements

Assets and liabilities that are recorded at fair value in the Condensed Consolidated Balance Sheets are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined 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 exchange-traded derivatives and equity securities.

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 September 30, 2011, there were no significant transfers between levels.

The following tables present information about CERC's assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of December 31, 2010 and September 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 September 30, 2011
	(in millions)
Assets
Corporate equities	$	1	$	-	$	-	$	-		$	1
Investments, including money market funds		11		-		-		-			11
Natural gas derivatives		8		72		7		(23	)		64
Total assets	$	20	$	72	$	7	$	(23	)	$	76
Liabilities
Natural gas derivatives		11		96		4		(55	)		56
Total liabilities	$	11	$	96	$	4	$	(55	)	$	56

(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 $32 million posted with the same counterparties.

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

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	Three Months Ended September 30,
	2010			2011
	(in millions)
Beginning balance	$	5		$	5
Total unrealized losses:
Included in earnings		-			(1	)
Total settlements, gross (1):
Included in earnings		(2	)		(1	)
Ending balance	$	3		$	3
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	1		$	(1	)

(1)

During both the three months ended September 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
	Nine Months Ended September 30,
	2010			2011
	(in millions)
Beginning balance	$	(6	)	$	3
Total unrealized gains (losses):
Included in earnings		2			3
Included in regulatory assets		(1	)		-
Total settlements, gross (1):
Included in earnings		(1	)		(3	)
Included in regulatory assets		9			-
Ending balance	$	3		$	3
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	4		$	2

(1)

During both the nine months ended September 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				September 30, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	2,925	$	3,158	$	2,775	$	3,091

- Definition

Tabular disclosure of the fair value measurement of assets and liabilities which includes [financial] instruments measured at fair value that are classified in stockholders' equity. Such assets and liabilities may be measured on a recurring or nonrecurring basis. The disclosures which may be required or desired include: (1) for assets and liabilities measured on a recurring basis, disclosure may include: (a) the fair value measurements at the reporting date; (b) the level within the fair value hierarchy in which the fair value measurements in their entirety fall, segregating fair value measurements using quoted prices in active markets for identical assets or liabilities (Level 1), significant other observable inputs (Level 2), and significant unobservable inputs (Level 3); (c) for fair value measurements using significant unobservable inputs (Level 3), a reconciliation of the beginning and ending balances, separately presenting changes during the period attributable to the following: (i) total gains or losses for the period (realized and unrealized), segregating those gains or losses included in earnings (or changes in net assets), and a description of where those gains or losses included in earnings (or changes in net assets) are reported in the statement of income (or activities); (ii) purchases, sales, issuances, and settlements (net); (iii) transfers in and transfers out of Level 3 (for example, transfers due to changes in the observability of significant inputs); (d) the amount of the total gains or losses for the period in subparagraph (c) (i) above included in earnings (or changes in net assets) that are attributable to the change in unrealized gains or losses relating to those assets and liabilities still held at the reporting date and a description of where those unrealized gains or losses are reported in the statement of income (or activities); (e) the valuation technique(s) used to measure fair value and a discussion of changes in valuation techniques, if any, during the period and (2) for assets and liabilities that are measured at fair value on a nonrecurring basis (for example, impaired assets) disclosure may include, in addition to (a) above: (a) the reasons for the fair value measurements recorded; (b) the same as (b) above; (c) for fair value measurements using significant unobservable inputs (Level 3), a description of the inputs and the information used to develop the inputs; and (d) the valuation technique(s) used to measure fair value and a discussion of changes, if any, in the valuation technique(s) used to measure similar assets and/or liabilities in prior periods. Where the quoted price in an active market for the identical liability is not available, the Level 1 input is the quoted price of an identical liability when traded as an asset.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-URI http://asc.fasb.org/extlink&oid=6925170&loc=d3e19296-110258

+ Details

Goodwill

9 Months Ended

Sep. 30, 2011

Goodwill [Abstract]

Goodwill

Goodwill by reportable business segment as of both December 31, 2010 and September 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

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

CERC performed the test as of July 1, 2011, its annual impairment testing date, and determined that no impairment existed.

- Definition

Tabular disclosure of goodwill by reportable segment and in total. Disclosure details may include, but are not limited to, the carrying amount of goodwill, goodwill acquired during the year, goodwill impairment losses recognized, goodwill written-off due to the sale of a business unit, goodwill not yet allocated, and any other changes to goodwill.

+ References + Details

Comprehensive Income

9 Months Ended

Sep. 30, 2011

Comprehensive Income [Abstract]

Comprehensive Income

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2011		2010		2011
	(in millions)
Net income	$	42	$	43	$	181	$	223
Other comprehensive income:
Adjustment to postretirement plans (net of tax of $-0-, $-0-, $-0- and $-0-)		-		-		-		-
Other comprehensive income		-		-		-		-
Comprehensive income	$	42	$	43	$	181	$	223

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

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

- Definition

The entire disclosure for comprehensive income. Includes, but is not limited to, the following: 1) the amount of income tax expense or benefit allocated to each component of other comprehensive income, including reclassification adjustments, 2) the reclassification adjustments for each classification of other comprehensive income and 3) the ending accumulated balances for each component of comprehensive income. Components of comprehensive income include: (1) foreign currency translation adjustments; (2) gains (losses) on foreign currency transactions that are designated as, and are effective as, economic hedges of a net investment in a foreign entity; (3) gains (losses) on intercompany foreign currency transactions that are of a long-term-investment nature, when the entities to the transaction are consolidated, combined, or accounted for by the equity method in the reporting enterprise's financial statements; (4) change in the market value of a futures contract that qualifies as a hedge of an asset reported at fair value; (5) unrealized holding gains (losses) on available-for-sale securities and that resulting from transfers of debt securities from the held-to-maturity category to the available-for-sale category; (6) a net loss recognized as an additional pension liability not yet recognized as net periodic pension cost; and (7) the net gain (loss) and net prior service cost or credit for pension plans and other postretirement benefit plans.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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+ Details

Related Party Transactions	9 Months Ended
Related Party Transactions	Sep. 30, 2011
Related Party Transactions [Abstract]
Related Party Transactions	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 $408 million at December 31, 2010 and September 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 nine months ended September 30, 2010, CERC had net interest expense of $1 million related to affiliate borrowings. For each of the three and nine months ended September 30, 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 $38 million for both the three months ended September 30, 2010 and 2011 and $112 million and $119 million for the nine months ended September 30, 2010 and 2011, respectively, and are included primarily in operation and maintenance expenses.

- Definition

The entire disclosure for related party transactions, including the nature of the relationship(s), a description of the transactions, the amount of the transactions, the effects of any change in the method of establishing the terms of the transaction from the previous period, stated interest rate, expiration date, terms and manner of settlement per the agreement with the related party, and amounts due to or from related parties. If the entity and one or more other entities are under common ownership or management control and this control affects the operating results or financial position, disclosure includes the nature of the control relationship even if there are no transactions between the entities. Disclosure may also include the aggregate amount of current and deferred tax expense for each statement of earnings presented where the entity is a member of a group that files a consolidated tax return, the amount of any tax related balances due to or from affiliates as of the date of each statement of financial position presented, the principal provisions of the method by which the consolidated amount of current and deferred tax expense is allocated to the members of the group and the nature and effect of any changes in that method. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

+ References

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-Publisher SEC
-Name Regulation S-X (SX)
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-Article 4
-Section 08
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Short-term Borrowings and Long-term Debt

9 Months Ended

Sep. 30, 2011

Short-term Borrowings and Long-term Debt [Abstract]

Short-term Borrowings and Long-term Debt

(a) Short-term Borrowings

Receivables Facility. CERC's receivables facility terminated pursuant to its terms on September 14, 2011. As of December 31, 2010 the facility size was $160 million and 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 $84 million as of December 31, 2010 and September 30, 2011, respectively.

(b) Long-term Debt

Revolving Credit Facility. In the third quarter of 2011, CERC's revolving credit facility was replaced with a five-year revolving credit facility of similar borrowing capacity. As of December 31, 2010 and September 30, 2011, CERC had the following revolving credit facilities and utilization of such facilities (in millions):

December 31, 2010								September 30, 2011
Size of Facility		Loans		Letters of Credit		Commercial Paper		Size of Facility		Loans		Letters of Credit		Commercial Paper
$	915	$	-	$	-	$	183	$	950	$	-	$	-	$	142

CERC Corp.'s $950 million credit facility, which is scheduled to terminate September 9, 2016, can be drawn at London Interbank Offered Rate (LIBOR) plus 150 basis points based on CERC Corp.'s current credit ratings. The facility contains a debt to total capitalization covenant which limits debt to 65% of its total capitalization.

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.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References + Details

Commitments and Contingencies	9 Months Ended
Commitments and Contingencies	Sep. 30, 2011
Commitments and Contingencies [Abstract]
Commitments and Contingencies	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 September 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 September 30, 2011, minimum payment obligations for natural gas supply commitments are approximately $181 million for the remaining three months in 2011, $499 million in 2012, $498 million in 2013, $388 million in 2014, $235 million in 2015 and $410 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 September 30, 2011, CEFS had spent approximately $390 million on the 600 MMcf per day project, including the purchase of the original facilities, and expects to incur up to an additional $35 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, 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. The plaintiffs have appealed this ruling to the United States Court of Appeals for the Ninth Circuit. 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 September 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 $6 million to $41 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (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 September 30, 2011, CERC had collected $5.4 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. On September 12, 2011, the First Circuit Court of Appeals dismissed the plaintiff's appeal with respect to CERC. 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 a number of 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 $100 million as of September 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. As a result of market conditions in the fourth quarter of 2011, CERC has provided notice to GenOn of its obligation to post additional security in December 2011. 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.

- Definition

The entire disclosure for commitments and contingencies.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 14
-Paragraph 3
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 9, 10, 11, 12
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Subparagraph (SX 210.5-02.25)
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-Publisher FASB
-Name Accounting Standards Codification
-Topic 440
-SubTopic 10
-Section 50
-Paragraph 2
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+ Details

Income Taxes

9 Months Ended

Sep. 30, 2011

Income Taxes [Abstract]

Income Taxes

During the three and nine months ended September 30, 2010, the effective tax rate was 38% and 44%, respectively. During the three and nine months ended September 30, 2011, the effective tax rate was 38% and 39%, respectively. The comparability of the effective tax rate for the nine months ended September 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 September 30, 2011:

	December 31, 2010			September 30, 2011
	(in millions)
Unrecognized tax benefits	$	11		$	8
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 $17 million primarily as a result of the acceptance by the IRS of a refund claim related to the timing of a deduction for debt issuance costs. 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.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

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-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 136, 172
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Reportable Business Segments

9 Months Ended

Sep. 30, 2011

Reportable Business Segments [Abstract]

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 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 September 30, 2010
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)
Natural Gas Distribution	$	395	$	3		$	(4	)
Competitive Natural Gas Sales and Services		638		9			7
Interstate Pipelines		136		34			68
Field Services		81		13			40
Other Operations		-		-			-
Eliminations		-		(59	)		-
Consolidated	$	1,250	$	-		$	111

	For the Three Months Ended September 30, 2011
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)
Natural Gas Distribution	$	379	$	5		$	(2	)
Competitive Natural Gas Sales and Services		580		4			(10	)
Interstate Pipelines		104		31			60
Field Services		108		9			61
Other Operations		-		-			2
Eliminations		-		(49	)		-
Consolidated	$	1,171	$	-		$	111

	For the Nine Months Ended September 30, 2010
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2010
Natural Gas Distribution	$	2,390	$	10		$	145		$	4,575
Competitive Natural Gas Sales and Services		2,032		27			16			1,190
Interstate Pipelines		352		104			207			3,672
Field Services		205		37			94			1,803
Other Operations		-		-			(2	)		659
Eliminations		-		(178	)		-			(1,361	)
Consolidated	$	4,979	$	-		$	460		$	10,538

	For the Nine Months Ended September 30, 2011
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)			Total Assets as of September 30, 2011
Natural Gas Distribution	$	2,034	$	14		$	153		$	4,379
Competitive Natural Gas Sales and Services		1,858		18			3			1,108
Interstate Pipelines		328		96			196			3,826
Field Services		274		31			136			1,862
Other Operations		-		-			(3	)		435
Eliminations		-		(159	)		-			(1,333	)
Consolidated	$	4,494	$	-		$	485		$	10,277

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 131
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+ Details

Other Current Assets and Liabilities	9 Months Ended
Other Current Assets and Liabilities	Sep. 30, 2011
Other Current Assets and Liabilities [Abstract]
Other Current Assets and Liabilities	Other Current Assets and Liabilities Included in other current assets on the Condensed Consolidated Balance Sheets at December 31, 2010 and September 30, 2011 was $23 million and $14 million, respectively, of margin deposits and $99 million and $57 million, respectively, of under-recovered gas cost. Included in other current liabilities on the Condensed Consolidated Balance Sheets at December 31, 2010 and September 30, 2011 was $94 million and $20 million, respectively, of over-recovered gas cost.