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Document and Entity Information Document - USD ($) shares in Thousands, $ in Millions	9 Months Ended
	Sep. 30, 2011	Oct. 14, 2011	Jun. 30, 2010
Entity Information [Line Items]
Entity Registrant Name	CENTERPOINT ENERGY INC.
Entity Central Index Key	0001130310
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		425,932,721
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 5,507,110,378

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	$ 1,881	$ 1,908	$ 6,305	$ 6,687
Expenses:
Natural gas	735	808	2,989	3,521
Operation and maintenance	448	444	1,333	1,268
Depreciation and amortization	253	243	677	660
Taxes other than income taxes	88	86	282	291
Total	1,524	1,581	5,281	5,740
Operating Income	357	327	1,024	947
Other Income (Expense):
Gain (loss) on marketable securities	(80)	19	(30)	35
Gain (loss) on indexed debt securities	88	(5)	65	0
Interest and other finance charges	(114)	(121)	(341)	(364)
Interest on transition and system restoration bonds	(31)	(34)	(96)	(106)
Equity in earnings of unconsolidated affiliates	8	10	22	22
Return on true-up balance	352	0	352	0
Other, net	10	3	19	7
Total	233	(128)	(9)	(406)
Income Before Income Taxes and Extraordinary Item	590	199	1,015	541
Income tax expense	204	76	362	223
Income Before Extraordinary Item	386	123	653	318
Extraordinary Item, net of tax	587	0	587	0
Net Income	$ 973	$ 123	$ 1,240	$ 318
Basic Earnings Per Share:
Income Before Extraordinary Item	$ 0.90	$ 0.29	$ 1.53	$ 0.79
Extraordinary Item, net of tax	1.38	0.00	1.38	0.00
Net Income	2.28	0.29	2.91	0.79
Diluted earnings per share:
Income Before Extraordinary Item	0.90	0.29	1.52	0.78
Extraordinary Item, net of tax	1.37	0.00	1.37	0.00
Net Income	2.27	0.29	2.89	0.78
Dividends Declared Per Share	$ 0.1975	$ 0.195	$ 0.5925	$ 0.585
Weighted Average Shares Outstanding, Basic	425,885,000	422,178,000	425,517,000	404,957,000
Weighted Average Shares Outstanding, Diluted	428,842,000	424,968,000	428,452,000	407,728,000

Balance Sheet Parentheticals (Parentheticals) - USD ($) $ in Millions	Sep. 30, 2011	Dec. 31, 2010
Current Assets:
Cash and cash equivalents, VIE	$ 103	$ 198
Accounts receivable, net, VIE	73	49
Prepaid expenses and other current assets, VIE	41	39
Other Assets:
Regulatory assets, VIE	$ 2,352	$ 2,597
Common stock, shares outstanding	425,919,192	424,746,177

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Sep. 30, 2011	Dec. 31, 2010
Current Assets:
Cash and cash equivalents ($198 and $103 related to VIEs at December 31, 2010 and September 30, 2011, respectively)	$ 103	$ 199
Investment in marketable securities	337	367
Accounts receivable, net ($49 and $73 related to VIEs at December 31, 2010 and September 30, 2011, respectively)	722	835
Accrued unbilled revenues	160	340
Natural gas inventory	250	211
Materials and supplies	168	164
Non-trading derivative assets	52	54
Taxes receivable	0	138
Prepaid expenses and other current assets ($39 and $41 related to VIEs at December 31, 2010 and September 30, 2011, respectively)	190	274
Total current assets	1,982	2,582
Property, Plant and Equipment:
Property, plant and equipment	16,591	16,005
Less accumulated depreciation and amortization	4,433	4,273
Property, plant and equipment, net	12,158	11,732
Other Assets:
Goodwill	1,696	1,696
Regulatory assets ($2,597 and $2,352 related to VIEs at December 31, 2010 and September 30, 2011, respectively)	4,475	3,446
Non-trading derivative assets	12	15
Investment in unconsolidated affiliates	474	468
Other	154	172
Total other assets	6,811	5,797
Total Assets	20,951	20,111
Current Liabilities:
Short-term borrowings	84	53
Current portion of VIE transition and system restoration bonds long-term debt	307	283
Current portion of indexed debt	130	126
Current portion of other long-term debt	46	19
Indexed debt securities derivative	167	232
Accounts payable	417	667
Taxes accrued	184	156
Interest accrued	118	171
Non-trading derivative liabilities	53	68
Accumulated deferred income taxes, net	494	407
Other	319	438
Total current liabilities	2,319	2,620
Other Liabilities:
Accumulated deferred income taxes, net	3,814	2,934
Non-trading derivative liabilities	3	16
Benefit obligations	842	906
Regulatory liabilities	1,033	989
Other	236	447
Total other liabilities	5,928	5,292
Long-term Debt:
VIE transition and system restoration bonds	2,215	2,522
Other	6,282	6,479
Total long-term debt	8,497	9,001
Commitments and Contingencies (Note 12)
Shareholders' Equity:
Common stock (424,746,177 shares and 425,919,192 shares outstanding at December 31, 2010 and September 30, 2011, respectively)	4	4
Additional paid-in capital	4,114	4,100
Retained earnings (accumulated deficit)	199	(789)
Accumulated other comprehensive loss	(110)	(117)
Total shareholders' equity	4,207	3,198
Total Liabilities and Shareholders' Equity	$ 20,951	$ 20,111

Condensed Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Cash Flows from Operating Activities:
Net income	$ 1,240	$ 318
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	677	660
Amortization of deferred financing costs	22	21
Deferred income taxes	404	112
Extraordinary Item, net of tax	(587)	0
Return on true-up balance	(352)	0
Unrealized loss (gain) on marketable securities	30	(35)
Unrealized gain on indexed debt securities	(65)	0
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	245	434
Inventory	(50)	(83)
Taxes receivable	138	(113)
Accounts payable	(215)	(283)
Fuel cost over (under) recovery	(52)	43
Non-trading derivatives, net	(10)	(16)
Margin deposits, net	61	(38)
Interest and taxes accrued	(25)	(56)
Net regulatory assets and liabilities	22	23
Other current assets	14	17
Other current liabilities	(23)	(38)
Other assets	(1)	(8)
Other liabilities	(49)	2
Other, net	15	13
Net cash provided by operating activities	1,449	983
Cash Flows from Investing Activities:
Capital expenditures	(960)	(1,053)
Increase in restricted cash of transition and system restoration bonds companies	(2)	(1)
Investment in unconsolidated affiliates	(9)	(21)
Cash received from U.S Department of Energy grant	110	58
Other, net	13	3
Net cash used in investing activities	(848)	(1,014)
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	(909)	(783)
Cash paid for debt exchange	(58)	0
Debt issuance costs	(23)	(2)
Payment of common stock dividends	(252)	(236)
Proceeds from issuance of common stock, net	5	392
Other, net	0	1
Net cash used in financing activities	(697)	(610)
Net Decrease in Cash and Cash Equivalents	(96)	(641)
Cash and Cash Equivalents at Beginning of Period	199	740
Cash and Cash Equivalents at End of Period	103	99
Cash Payments:
Interest, net of capitalized interest	470	505
Income taxes (refunds), net	(204)	210
Non-cash transactions:
Accounts payable related to capital expenditures	$ 101	$ 104

Background and Basis of Presentation

9 Months Ended

Sep. 30, 2011

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Background and Basis of Presentation

General. Included in this Quarterly Report on Form 10-Q (Form 10-Q) of CenterPoint Energy, Inc. are the condensed consolidated interim financial statements and notes (Interim Condensed Financial Statements) of CenterPoint Energy, Inc. and its subsidiaries (collectively, CenterPoint Energy). 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 CenterPoint Energy for the year ended December 31, 2010 (CenterPoint Energy Form 10-K).

Background. CenterPoint Energy, Inc. is a public utility holding company. CenterPoint Energy’s operating subsidiaries own and operate electric transmission and distribution facilities, natural gas distribution facilities, interstate pipelines and natural gas gathering, processing and treating facilities. As of September 30, 2011, CenterPoint Energy’s indirect wholly owned subsidiaries included:


•	CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in the electric transmission and distribution business in the Texas Gulf Coast area that includes the city of Houston; and

•

CenterPoint Energy Resources Corp. (CERC Corp. and, together with its subsidiaries, CERC), which owns and operates natural gas distribution systems. 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.

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.

CenterPoint Energy’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 CenterPoint Energy’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 CenterPoint Energy’s reportable business segments, see Note 14.

- 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]
Description of New Accounting Pronouncements Not yet Adopted [Text Block]	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. CenterPoint Energy's adoption of this new guidance did not have a material impact on its financial position, results of operations or cash flows. See Note 6 for the required disclosures. 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. CenterPoint Energy 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. CenterPoint Energy 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. CenterPoint Energy 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 CenterPoint Energy’s consolidated financial position, results of operations or cash flows upon adoption.

Employee Benefit Plans

9 Months Ended

Sep. 30, 2011

Employee Benefit Plans [Abstract]

Employee Benefit Plans

CenterPoint Energy’s net periodic cost includes the following components relating to pension and postretirement benefits:



	Three Months Ended September 30,
	2010						2011
	Pension Benefits ⁽¹⁾			Postretirement Benefits			Pension Benefits ⁽¹⁾			Postretirement Benefits
	(in millions)
Service cost	$	8		$	—		$	8		$	—
Interest cost	26			7			25			5
Expected return on plan assets	(27		)	(2		)	(29		)	(2		)
Amortization of prior service credit	—			—			1			1
Amortization of net loss	15			—			14			—
Amortization of transition obligation	—			2			—			2
Net periodic cost	$	22		$	7		$	19		$	6



	Nine Months Ended September 30,
	2010						2011
	Pension Benefits ⁽¹⁾			Postretirement Benefits			Pension Benefits ⁽¹⁾			Postretirement Benefits
	(in millions)
Service cost	$	24		$	1		$	25		$	1
Interest cost	77			19			75			17
Expected return on plan assets	(82		)	(7		)	(87		)	(7		)
Amortization of prior service credit	2			2			3			3
Amortization of net loss	44			—			42			1
Amortization of transition obligation	—			5			—			5
Net periodic cost	$	65		$	20		$	58		$	20

________________

(1)

Net periodic cost in these tables is before considering amounts subject to overhead allocations for capital expenditure projects or for amounts subject to deferral for regulatory purposes. CenterPoint Houston’s actuarially determined pension expense in excess of amounts authorized for recovery in base rates is being deferred for rate making purposes. CenterPoint Houston deferred as a regulatory asset $6 million and $2 million, respectively, in pension expense during the three months ended September 30, 2010 and 2011, and $18 million and $13 million, respectively, in pension expense during the nine months ended September 30, 2010 and 2011.

CenterPoint Energy expects to contribute approximately $75 million to its pension plans in 2011, of which approximately $69 million and $72 million, respectively, were contributed during the three and nine months ended September 30, 2011.

CenterPoint Energy expects to contribute approximately $18 million to its postretirement benefits plan in 2011, of which approximately $0 and $11 million, respectively, were 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

Sep. 30, 2011

Regulatory Matters [Abstract]

Regulatory Matters


(a)	Resolution of True-Up Appeal

In March 2004, CenterPoint Houston filed a true-up application with the Public Utility Commission of Texas (Texas Utility Commission), requesting recovery of $3.7 billion, excluding interest, as allowed under the Texas Electric Choice Plan. In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and provided for adjustment of the amount to be recovered to include interest on the balance until recovery, along with the principal portion of additional excess mitigation credits returned to customers after August 31, 2004 and certain other adjustments. To reflect the impact of the True-Up Order, in 2004 and 2005, CenterPoint Energy recorded a net after-tax extraordinary loss of $947 million.

Various parties, including CenterPoint Houston, appealed the True-Up Order. These appeals were heard first by a district court in Travis County, Texas, then by the Texas Third Court of Appeals and finally by the Texas Supreme Court. On March 18, 2011, the Texas Supreme Court issued a unanimous ruling on such appeals in which it affirmed in part and reversed in part the decision of the Texas Utility Commission . In June 2011, the Texas Supreme Court denied all motions for rehearing and issued a final mandate remanding the case to the Texas Utility Commission for further proceedings (the Remand Proceeding).

In September 2011, CenterPoint Houston reached an agreement in principle with the staff of the Texas Utility Commission and certain intervenors to settle the issues in the Remand Proceeding (the Settlement) and requested that the Texas Utility Commission abate the procedural schedule for the Remand Proceeding and reserve ruling on pending motions or issues until the Texas Utility Commission reviewed the Settlement. At its open meeting on October 13, 2011, the Texas Utility Commission voted to approve a final order (the Final Order) in the Remand Proceeding. The Final Order provides that (i) CenterPoint Houston is entitled to recover an additional true-up balance of $1.695 billion (the Recoverable True-Up Balance) in the Remand Proceeding, (ii) no further interest will accrue on the Recoverable True-Up Balance, and (iii) CenterPoint Houston will reimburse certain parties for their reasonable rate case expenses. The Final Order is consistent with the terms of the Settlement, which resolved all matters in the Remand Proceeding. The Final Order was issued by the Texas Utility Commission on October 19, 2011. Any party may appeal the Final Order by filing a motion for rehearing within 20 days from the date the party received notice of the Final Order.

On October 27, 2011, the Texas Utility Commission issued a financing order (the Financing Order) that authorizes the issuance of transition bonds by CenterPoint Houston to securitize the Recoverable True-Up Balance. The Financing Order is subject to appeal within 15 days from the date it was issued. The timing and completion of any transition bond offering will ultimately depend on a number of factors, including actions by the Texas Utility Commission, any appeals of the Financing Order, and future market conditions.

As a result of the Final Order, CenterPoint Houston recorded a pre-tax extraordinary gain of $921 million ($587 million after-tax of $334 million) and $352 million ($224 million after-tax) of Other Income related to a portion of interest on the appealed amount. An additional $405 million ($258 million after-tax) will be recorded as an equity return over the life of the transition bonds.

As of September 30, 2011, CenterPoint Energy has not recognized an allowed equity return of $165 million on the portion of CenterPoint Houston’s true-up balance that had previously been securitized because such return will be recognized as it is recovered in rates. During the three months ended September 30, 2010 and 2011, CenterPoint Houston recognized approximately $5 million and $6 million, respectively, of the allowed equity return not previously recognized. During the nine months ended September 30, 2010 and 2011, CenterPoint Houston recognized approximately $12 million and $13 million, respectively, of the allowed equity return not previously recognized.


(b)	Rate Proceedings

CenterPoint Houston

June 2010 Rate Proceeding. As required under the final order in its 2006 rate proceeding, in June 2010 CenterPoint Houston filed an application to change rates with the Texas Utility Commission and the cities in its service area.

Following hearings in the fall of 2010, the Texas Utility Commission issued its order on May 12, 2011. In response to motions filed by several parties, including CenterPoint Houston, on June 23, 2011, the Texas Utility Commission issued an order on rehearing, which addressed certain errors and inconsistencies identified in its prior decision. CenterPoint Houston implemented revised rates on September 1, 2011 based on the order on rehearing. The order on rehearing has been appealed to the Texas courts by various parties; however, a procedural schedule has not been established.

The order on rehearing provides for a base rate increase for CenterPoint Houston of approximately $14.7 million per year for delivery charges to the REPs and a decrease to charges to wholesale transmission customers of $12.3 million per year. Further, the order adopts a mechanism to track amounts for uncertain tax positions and provide for ultimate recovery of those costs. The order authorizes a return on equity for CenterPoint Houston of 10%, a cost of debt of 6.74%, a capital structure comprised of 55% debt and 45% common equity, and an overall rate of return of 8.21%. The decision also implements CenterPoint Houston’s request to reconcile costs incurred for the advanced metering system (AMS) project and to shorten the period for collecting the AMS surcharge from twelve to six years for residential customers in order to reflect the funds received from the U.S. Department of Energy. As a result of the Texas Utility Commission’s order, CenterPoint Houston anticipates that normalized annual operating income will be reduced by approximately $30 million.

Other. In May 2009, CenterPoint Houston filed an application at the Texas Utility Commission seeking approval of certain estimated 2010 energy efficiency program costs, an energy efficiency performance bonus for 2008 programs, and carrying costs totaling approximately $10 million. The application sought to begin recovery of these costs through a surcharge effective July 1, 2010. In October 2009, the Texas Utility Commission issued its order approving recovery of the 2010 energy efficiency program costs and a partial performance bonus of approximately $8 million, plus carrying costs, but disallowed recovery of a performance bonus of $2 million on approximately $10 million in 2008 energy efficiency costs expended pursuant to the terms of a settlement agreement in a prior rate case. CenterPoint Houston began collecting the approved amounts in July 2010. CenterPoint Houston appealed the denial of the full 2008 performance bonus to the 98th district court in Travis County, Texas. In October 2010, the district court upheld the Texas Utility Commission’s decision. In February 2011, CenterPoint Houston appealed the district court’s judgment to the Texas Third Court of Appeals at Austin, Texas. Oral arguments were heard in October 2011, and the case remains pending.

In April 2010, CenterPoint Houston filed an application with the Texas Utility Commission seeking approval of the recovery of $14.4 million related to estimated 2011 energy efficiency programs, an energy efficiency performance bonus for 2009 programs, and recovery of revenue losses related to the implementation of the 2009 energy efficiency program. The application sought to begin recovery of these costs through a surcharge beginning in January 2011. In November 2010, the Texas Utility Commission issued its order approving recovery of approximately $11 million of the 2011 energy efficiency program costs and a performance bonus, but disallowed recovery of a performance bonus of $2 million on the 2009 energy efficiency costs expended pursuant to the terms of the settlement agreement referenced above. The Texas Utility Commission further concluded that it does not have statutory authority to permit recovery of the approximately $1.4 million in lost revenue associated with 2009 energy efficiency programs. CenterPoint Houston began collecting the approved amounts in January 2011, but has appealed the denial of the full 2009 performance bonus and lost revenue to the 201st district court in Travis County, Texas, where the case remains pending.

In April 2011, CenterPoint Houston filed an application with the Texas Utility Commission seeking approval of the recovery in 2012 of approximately $44.3 million consisting of: (1) estimated 2012 energy efficiency program costs of approximately $35.8 million; (2) an energy efficiency performance bonus based on CenterPoint Houston’s 2010 program achievements of approximately $5.8 million; (3) the amount of lost revenues due to verified and reported 2010 energy savings of approximately $2.2 million; and (4) approximately $0.5 million for under-recovery of 2010 program costs. In the preliminary order in this proceeding, the Texas Utility Commission has excluded approximately $2.1 million of the requested performance bonus for the 2010 programs and has concluded that it does not have the statutory authority to permit recovery of the requested $2.2 million of lost revenues associated with the 2010 programs. In August 2011, CenterPoint Houston and the parties agreed to forego a hearing and admit evidence supporting the recovery of (1) the estimated 2012 energy efficiency costs of approximately $35.8 million, (2) an energy efficiency performance bonus of approximately $3.6 million, and (3) approximately $0.5 million for under-recovery of 2010 program costs. CenterPoint Houston has filed notification that it reserves its right to appeal the denial of the full 2010 performance bonus and lost revenues. The proposed rate adjustments are expected to take effect with the commencement of CenterPoint Houston’s January 2012 billing month.

In August 2011, CenterPoint Houston filed a Transmission Cost of Service application with the Texas Utility Commission seeking an increase in annual revenue of approximately $3.4 million. In September 2011, the Texas Utility Commission approved the application and the rates became effective at that time.

In September 2011, a new rule of the Texas Utility Commission relating to a Distribution Cost Recovery Factor (DCRF) became effective. The new rule permits an electric utility such as CenterPoint Houston to file each year to recover through a separate DCRF a return on changes to certain distribution-related capital investments, net of any changes in distribution-related accumulated deferred income taxes, as well as related changes to depreciation expense and taxes. The utility is allowed to request one DCRF annually unless in the previous year it was found to have earned in excess of its authorized return on equity as calculated in its annual earnings monitoring report on a weather-adjusted basis, in which case the DCRF is not available. The utility is limited to four DCRF filings and then must seek a full rate proceeding before it can request a subsequent DCRF. The rule expires January 1, 2017.

In October 2011, CenterPoint Houston and certain other parties filed a non-unanimous stipulation (Transmission Stipulation) with the Texas Utility Commission to resolve claims related to the “transition mechanism” component of certain invalidated transmission pricing rules. The Transmission Stipulation resolves all remaining claims that arose from or relate to wholesale transmission service and charges within the Electric Reliability Council of Texas, Inc. (ERCOT) for the period from September 1, 1999 to December 31, 1999 during which the Texas Utility Commission had continued to utilize the “transition mechanism” component of the invalidated transmission pricing rules in setting ERCOT transmission rates. The Transmission Stipulation was filed by all parties to the proceeding, except CPS Energy. Under the Transmission Stipulation, CenterPoint Houston's payment of $5.6 million is to be made within 30 days after issuance of a final appealable order. It is expected that a final appealable order will be issued in early 2012. CenterPoint Houston will seek recovery of the payment through its Transmission Cost Recovery Factor mechanism.

Gas Operations

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. CenterPoint Energy 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

CenterPoint Energy is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. CenterPoint Energy 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 CenterPoint Energy’s Condensed Consolidated Balance Sheets at their fair value unless CenterPoint Energy 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 CenterPoint Energy’s marketing, risk management services and hedging activities. The committee’s duties are to establish CenterPoint Energy’s commodity risk policies, allocate board-approved commercial risk limits, approve the use of new products and commodities, monitor positions and ensure compliance with CenterPoint Energy’s risk management policies and procedures and limits established by CenterPoint Energy’s board of directors.

CenterPoint Energy’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. CenterPoint Energy 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, CenterPoint Energy 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, CenterPoint Energy 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, CenterPoint Energy 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, CenterPoint Energy 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. CenterPoint Energy 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 and in CenterPoint Houston’s service territory.

CenterPoint Energy 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, CenterPoint Energy recognized losses of $0 and $5 million, respectively, related to these swaps. During the three and nine months ended September 30, 2011, CenterPoint Energy 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 CenterPoint Energy’s derivative instruments and hedging activities. The first two tables provide a balance sheet overview of CenterPoint Energy’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
Indexed debt securities derivative	Current Liabilities	—		232
Total		$	80	$	411

________________


(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 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 $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
Indexed debt securities derivative	Current Liabilities	—		167
Total		$	87	$	278

________________


(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 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 CenterPoint Energy’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. Unrealized gains and losses on indexed debt securities are recorded as Other Income (Expense) in the Condensed Statements of Consolidated Income.



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		)
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)	(5		)	88
Total		$	(5	)	$	85

________________


(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		)
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)	—			65
Total		$	(43	)	$	27

________________


(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.


(c)	Credit Risk Contingent Features

CenterPoint Energy enters into financial derivative contracts containing material adverse change provisions. These provisions could require CenterPoint Energy to post additional collateral if the Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc. credit ratings of CenterPoint Energy, Inc. 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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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Financial Accounting Standard (FAS)
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+ Details

Fair Value Measurements

9 Months Ended

Sep. 30, 2011

Fair Value Measurements [Abstract]

Fair Value Disclosures [Text Block]

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 CenterPoint Energy’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 CenterPoint Energy’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. CenterPoint Energy develops these inputs based on the best information available, including CenterPoint Energy’s own data. A market approach is utilized to value CenterPoint Energy’s Level 3 assets or liabilities.

CenterPoint Energy 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 CenterPoint Energy’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 CenterPoint Energy 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
			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments ⁽¹⁾			December 31, 2010
	(in millions)
Assets
Corporate equities	$	368	$	—	$	—	$	—		$	368
Investments, including money market funds	54		—		—		—			54
Natural gas derivatives	—		73		7		(11		)	69
Total assets	$	422	$	73	$	7	$	(11	)	$	491
Liabilities
Indexed debt securities derivative	$	—	$	232	$	—	$	—		$	232
Natural gas derivatives	8		167		4		(95		)	84
Total liabilities	$	8	$	399	$	4	$	(95	)	$	316

________________


(1)	Amounts represent the impact of legally enforceable master netting agreements that allow CenterPoint Energy 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
			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments ⁽¹⁾			September 30, 2011
	(in millions)
Assets
Corporate equities	$	339	$	—	$	—	$	—		$	339
Investments, including money market funds	54		—		—		—			54
Natural gas derivatives	8		72		7		(23		)	64
Total assets	$	401	$	72	$	7	$	(23	)	$	457
Liabilities
Indexed debt securities derivative	$	—	$	167	$	—	$	—		$	167
Natural gas derivatives	11		96		4		(55		)	56
Total liabilities	$	11	$	263	$	4	$	(55	)	$	223

________________


(1)	Amounts represent the impact of legally enforceable master netting agreements that allow CenterPoint Energy 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 CenterPoint Energy 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, CenterPoint Energy 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, CenterPoint Energy did not have Level 3 purchases or sales.

Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents, investments in debt and equity securities classified as “available-for-sale” and “trading” and short-term borrowings are estimated to be approximately equivalent to carrying amounts and have been excluded from the table below. The fair values of non-trading derivative assets and liabilities and CenterPoint Energy’s 2.00% Zero-Premium Exchangeable Subordinated Notes due 2029 indexed debt securities derivative 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	$	9,303	$	10,071	$	8,850	$	9,870

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44A, 44B
-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 107
-Paragraph 15C, 15D
-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
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15A
-Subparagraph a-d
-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 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15B
-Subparagraph a, b
-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 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 3, 10, 14, 15
-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 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32, 33, 34
-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 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 17-22, 27, 28
-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 8: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 12: http://www.xbrl.org/2003/role/presentationRef
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Goodwill

9 Months Ended

Sep. 30, 2011

Goodwill [Abstract]

Goodwill and Intangible Assets Disclosure [Text Block]

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

CenterPoint Energy 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.

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

- Definition

The entire disclosure for the aggregate amount of goodwill and a description of intangible assets, which may include (a) for amortizable intangible assets (also referred to as finite-lived intangible assets), the carrying amount, the amount of any significant residual value, and the weighted-average amortization period, (b) for intangible assets not subject to amortization (also referred to as indefinite-lived intangible assets), the carrying amount, and (c) the amount of research and development assets acquired and written off in the period, including the line item in the income statement in which the amounts written off are aggregated, if not readily apparent from the income statement. Also discloses (a) for amortizable intangibles assets in total and by major class, the gross carrying amount and accumulated amortization, the total amortization expense for the period, and the estimated aggregate amortization expense for each of the five succeeding fiscal years, (b) for intangible assets not subject to amortization the carrying amount in total and by major class, and (c) for goodwill, in total and for each reportable segment, the changes in the carrying amount of goodwill during the period (including the aggregate amount of goodwill acquired, the aggregate amount of impairment losses recognized, and the amount of goodwill included in the gain (loss) on disposal of a reporting unit). If any part of goodwill has not been allocated to a reportable segment, discloses the unallocated amount and the reasons for not allocating. For each impairment loss recognized related to an intangible asset (excluding goodwill), discloses: (a) a description of the impaired intangible asset and the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method for determining fair value, (c) the caption in the income statement or the statement of activities in which the impairment loss is aggregated, and (d) the segment in which the impaired intangible asset is reported. For each goodwill impairment loss recognized, discloses: (a) a description of the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method of determining the fair value of the associated reporting unit, and (c) if a recognized impairment loss is an estimate not finalized and the reasons why the estimate is not final. May also disclose the nature and amount of any significant adjustments made to a previous estimate of an impairment loss.

+ References + Details

Comprehensive Income

9 Months Ended

Sep. 30, 2011

Comprehensive Income [Abstract]

Comprehensive Income (Loss) Note [Text Block]

Comprehensive Income

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



	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2010		2011		2010		2011
	(in millions)
Net income	$	123	$	973	$	318	$	1,240
Other comprehensive income:
Adjustment related to pension and other postretirement plans (net of tax of $2, $2, $5 and $5)	2		2		7		7
Reclassification of deferred loss from cash flow hedges realized in net income (net of tax of $-0-, $-0-, $-0- and $-0-)	1		—		1		—
Total	3		2		8		7
Comprehensive income	$	126	$	975	$	326	$	1,247

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



	December 31, 2010			September 30, 2011
	(in millions)
Adjustment related to pension and postretirement plans	$	(114	)	$	(107	)
Net deferred loss from cash flow hedges	(3		)	(3		)
Total accumulated other comprehensive loss	$	(117	)	$	(110	)

- 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)
-Number 130
-Paragraph 14-26
-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 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Reclassification Adjustments
-URI http://asc.fasb.org/extlink&oid=6522872

Reference 10: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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+ Details

Capital Stock	9 Months Ended
Capital Stock	Sep. 30, 2011
Capital Stock [Abstract]
Capital Stock	Capital Stock CenterPoint Energy, Inc. has 1,020,000,000 authorized shares of capital stock, comprised of 1,000,000,000 shares of $0.01 par value common stock and 20,000,000 shares of $0.01 par value preferred stock. At December 31, 2010, 424,746,343 shares of CenterPoint Energy common stock were issued and 424,746,177 shares were outstanding. At September 30, 2011, 425,919,358 shares of CenterPoint Energy common stock were issued and 425,919,192 shares were outstanding. Outstanding common shares exclude 166 treasury shares at both December 31, 2010 and September 30, 2011.

- Definition

The entire disclosure for shareholders' equity, comprised of portions attributable to the parent entity and noncontrolling interest, if any, including other comprehensive income (as applicable). Including, but not limited to: (1) balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings; (2) accumulated balance for each classification of other comprehensive income and total amount of comprehensive income; (3) amount and nature of changes in separate accounts, including the number of shares authorized and outstanding, number of shares issued upon exercise and conversion, and for other comprehensive income, the adjustments for reclassifications to net income; (4) rights and privileges of each class of stock authorized; (5) basis of treasury stock, if other than cost, and amounts paid and accounting treatment for treasury stock purchased significantly in excess of market; (6) dividends paid or payable per share and in the aggregate for each class of stock for each period presented; (7) dividend restrictions and accumulated preferred dividends in arrears (in aggregate and per share amount); (8) retained earnings appropriations or restrictions, such as dividend restrictions; (9) impact of change in accounting principle, initial adoption of new accounting principle and correction of an error in previously issued financial statements; (10) shares held in trust for Employee Stock Ownership Plan (ESOP); (11) deferred compensation related to issuance of capital stock; (12) note received for issuance of stock; (13) unamortized discount on shares; (14) description, terms, and number of warrants or rights outstanding; (15) shares under subscription and subscription receivables, effective date of new retained earnings after quasi-reorganization and deficit eliminated by quasi-reorganization and, for a period of at least ten years after the effective date, the point in time from which the new retained dates; and (16) retroactive effective of subsequent change in capital structure.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 12
-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
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Article 3

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Article 4
-Section 08
-Paragraph d

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 43
-Chapter 1
-Section B
-Paragraph 7, 11A
-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 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 129
-Paragraph 2, 3, 4, 5, 6, 7, 8
-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 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Article 4

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 15
-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 8: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 29, 30, 31
-Article 5

Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-Name Staff Accounting Bulletin (SAB)
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-Section E

Reference 10: http://www.xbrl.org/2003/role/presentationRef
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-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section C

Reference 11: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 505
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-Section S99
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-Subparagraph (SX 210.3-04)
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Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(d),(e))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

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-Publisher FASB
-Name Accounting Standards Codification
-Glossary Preferred Stock
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Reference 22: http://www.xbrl.org/2003/role/presentationRef
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Reference 23: http://www.xbrl.org/2003/role/presentationRef
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-Subparagraph (SAB TOPIC 4.C)
-URI http://asc.fasb.org/extlink&oid=6959260&loc=d3e187143-122770

+ 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 [Text Block]

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 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 Facilities. In the third quarter of 2011, the revolving credit facilities of CenterPoint Energy, CenterPoint Houston and CERC Corp. were replaced with five-year revolving credit facilities of similar borrowing capacity. As of December 31, 2010 and September 30, 2011, CenterPoint Energy, CenterPoint Houston and CERC Corp. 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
CenterPoint Energy	$	1,156	$	—	$	20	$	—	$	1,200	$	—	$	16	$	—
CenterPoint Houston	289		—		4		—		300		—		4		—
CERC Corp.	915		—		—		183		950		—		—		142
Total	$	2,360	$	—	$	24	$	183	$	2,450	$	—	$	20	$	142

CenterPoint Energy’s $1.2 billion credit facility, which is scheduled to terminate September 9, 2016, can be drawn at the London Interbank Offered Rate (LIBOR) plus 175 basis points based on CenterPoint Energy’s current credit ratings. The facility contains a debt (excluding transition and system restoration bonds) to earnings before interest, taxes, depreciation and amortization (EBITDA) covenant (as those terms are defined in the facility). The facility allows for a temporary increase of the permitted ratio in the financial covenant from 5 times to 5.5 times if CenterPoint Houston experiences damage from a natural disaster in its service territory and CenterPoint Energy certifies to the administrative agent that CenterPoint Houston has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive twelve-month period, all or part of which CenterPoint Houston intends to seek to recover through securitization financing. Such temporary increase in the financial covenant would be in effect from the date CenterPoint Energy delivers its certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of CenterPoint Energy’s certification or (iii) the revocation of such certification.

CenterPoint Houston’s $300 million credit facility, which is scheduled to terminate September 9, 2016, can be drawn at LIBOR plus 150 basis points based on CenterPoint Houston's current credit ratings. The facility contains a debt (excluding transition and system restoration bonds) to total capitalization covenant which limits debt to 65% of the borrower's total capitalization.

CERC Corp.’s $950 million credit facility, which is scheduled to terminate September 9, 2016, can be drawn at 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 CERC's 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

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 41%, respectively. During the three and nine months ended September 30, 2011, the effective tax rate was 35% and 36%, respectively. The most significant items affecting the comparability of the effective tax rate for the nine months ended September 30, 2010 and 2011 are a non-cash, $21 million increase in the 2010 income tax expense as a result of a change in tax law and a $9 million decrease in the 2011 income tax expense related to a decrease in accrued interest for tax reserves related to the potential normalization violation.

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, CenterPoint Energy reduced its deferred tax asset by approximately $32 million as of March 31, 2010. The portion of the reduction that CenterPoint Energy believes will be recovered through the regulatory process, or approximately $11 million, was recorded as an adjustment to regulatory assets. The remaining $21 million of the reduction in CenterPoint Energy’s deferred tax asset was reflected as a charge to income tax expense.

The following table summarizes CenterPoint Energy’s unrecognized tax benefits at December 31, 2010 and September 30, 2011:



	December 31, 2010		September 30, 2011
	(in millions)
Unrecognized tax benefits	$	252	$	52
Portion of unrecognized tax benefits that, if recognized, would reduce the effective income tax rate	17		20
Interest accrued on unrecognized tax benefits	12		—

The decrease of $200 million in unrecognized tax benefits from December 31, 2010 is primarily related to the remeasurement of unrecognized tax benefits for the potential normalization violation. As a result of the Settlement, discussed in Note 4(a), CenterPoint Houston has determined that the potential normalization violation has been prevented and consequently, recorded a reduction to the liability for unrecognized income tax benefits by $279 million during the three months ended September 30, 2011 of which $211 million was related to the balance as of December 31, 2010 with the remaining $68 million related to the six months ended June 30, 2011. The unrecognized tax benefit for the normalization issue was a temporary difference and, therefore, the decrease in the balance thereto resulted in an increase to the deferred tax liability of $268 million and a decrease in income tax expense of $11 million for the release of accrued interest expense.

It is reasonably possible that the total amount of unrecognized tax benefits could decrease in the range of $16 million to $35 million over the next 12 months, depending on the result of CenterPoint Energy’s administrative appeal relating to the Internal Revenue Service's (IRS) disallowance of CenterPoint Energy’s casualty loss deduction associated with the damage caused by Hurricane Ike. Additionally, the casualty loss deduction is a temporary difference and, therefore, any increase or decrease in the balance of unrecognized tax benefits related thereto would not affect the effective tax rate.

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

- 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

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-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
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 43, 44, 45, 46, 47, 48, 49
-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 4: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Commitments and Contingencies

9 Months Ended

Sep. 30, 2011

Commitments and Contingencies [Abstract]

Commitments and Contingencies


(a)	Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to CenterPoint Energy’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 CenterPoint Energy’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

Long-Term Gas Gathering and Treating Agreements

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, CenterPoint Houston or their 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 a subsidiary of NRG Energy, Inc. (NRG) 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, including CenterPoint Houston, 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 and CenterPoint Energy do not expect the ultimate outcome of the lawsuits to have a material impact on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.

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 owned by CenterPoint Energy contain or have contained asbestos insulation and other asbestos-containing materials. CenterPoint Energy or its subsidiaries 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. Some of the claimants have worked at locations owned by CenterPoint Energy, but most existing claims relate to facilities previously owned by CenterPoint Energy’s subsidiaries. CenterPoint Energy anticipates that additional claims like those received may be asserted in the future. In 2004, CenterPoint Energy sold its generating business, to which most of these claims relate, to Texas Genco LLC, which is now known as NRG Texas LP. Under the terms of the arrangements regarding separation of the generating business from CenterPoint Energy and its sale to NRG Texas LP, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by NRG Texas LP, but CenterPoint Energy has agreed to continue to defend such claims to the extent they are covered by insurance maintained by CenterPoint Energy, subject to reimbursement of the costs of such defense from NRG Texas LP. Although their ultimate outcome cannot be predicted at this time, CenterPoint Energy 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 CenterPoint Energy’s financial condition, results of operations or cash flows.

Other Environmental. From time to time CenterPoint Energy 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, CenterPoint Energy 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, CenterPoint Energy does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on CenterPoint Energy’s financial condition, results of operations or cash flows.

Other Proceedings

CenterPoint Energy 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. CenterPoint Energy regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. CenterPoint Energy does not expect the disposition of these matters to have a material adverse effect on CenterPoint Energy’s financial condition, results of operations or cash flows.


(d)	Guaranties

Prior to the distribution of CenterPoint Energy’s 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
-Publisher FASB
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-Subparagraph (SX 210.5-02.25)
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+ Details

Earnings Per Share

9 Months Ended

Sep. 30, 2011

Earnings Per Share [Abstract]

Earnings Per Share

The following table reconciles numerators and denominators of CenterPoint Energy’s basic and diluted earnings per share calculations:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2011		2010		2011
	(in millions, except share and per share amounts)
Basic earnings per share calculation:
Income before extraordinary item	$	123	$	386	$	318	$	653
Extraordinary item, net of tax	—		587		—		587
Net income	$	123	$	973	$	318	$	1,240

Weighted average shares outstanding	422,178,000		425,885,000		404,957,000		425,517,000

Basic earnings per share:
Income before extraordinary item	$	0.29	$	0.90	$	0.79	$	1.53
Extraordinary item, net of tax	—		1.38		—		1.38
Net income	$	0.29	$	2.28	$	0.79	$	2.91

Diluted earnings per share calculation:
Net income	$	123	$	973	$	318	$	1,240

Weighted average shares outstanding	422,178,000		425,885,000		404,957,000		425,517,000
Plus: Incremental shares from assumed conversions:
Stock options ⁽¹⁾	548,000		399,000		529,000		377,000
Restricted stock	2,242,000		2,558,000		2,242,000		2,558,000
Weighted average shares assuming dilution	424,968,000		428,842,000		407,728,000		428,452,000

Diluted earnings per share:
Income before extraordinary item	$	0.29	$	0.90	$	0.78	$	1.52
Extraordinary item, net of tax	—		1.37		—		1.37
Net income	$	0.29	$	2.27	$	0.78	$	2.89

________________


(1)	Options to purchase 1,522,444 shares were outstanding for both the three and nine months ended September 30, 2010, but were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares for the respective periods.

Reportable Business Segments

9 Months Ended

Sep. 30, 2011

Reportable Business Segments [Abstract]

Reportable Business Segments

CenterPoint Energy’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. CenterPoint Energy uses operating income as the measure of profit or loss for its business segments.

CenterPoint Energy’s reportable business segments include the following: Electric Transmission & Distribution, Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines, Field Services and Other Operations. The electric transmission and distribution function (CenterPoint Houston) is reported in the Electric Transmission & Distribution business segment. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers. Competitive Natural Gas Sales and Services represents CenterPoint Energy’s non-rate regulated gas sales and services operations, which consist of the following 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. Other Operations consists primarily of other corporate operations which support all of CenterPoint Energy’s business operations.

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)
Electric Transmission & Distribution	$	655	⁽¹⁾	$	—		$	212
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	3			—			4
Eliminations	—			(59		)	—
Consolidated	$	1,908		$	—		$	327



	For the Three Months Ended September 30, 2011
	Revenues from External Customers			Net Intersegment Revenues			Operating Income (Loss)
Electric Transmission & Distribution	$	707	⁽¹⁾	$	—		$	244
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	3			—			4
Eliminations	—			(49		)	—
Consolidated	$	1,881		$	—		$	357



	For the Nine Months Ended September 30, 2010
	Revenues from External Customers			Net Intersegment Revenues			Operating Income		Total Assets as of December 31, 2010
Electric Transmission & Distribution	$	1,699	⁽¹⁾	$	—		$	477	$	9,817
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	9			—			8		2,184			⁽²⁾
Eliminations	—			(178		)	—		(3,130		)
Consolidated	$	6,687		$	—		$	947	$	20,111



	For the Nine Months Ended September 30, 2011
	Revenues from External Customers			Net Intersegment Revenues			Operating Income		Total Assets as of September 30, 2011
Electric Transmission & Distribution	$	1,802	⁽¹⁾	$	—		$	530	$	11,084
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	9			—			6		1,897			⁽²⁾
Eliminations	—			(159		)	—		(3,205		)
Consolidated	$	6,305		$	—		$	1,024	$	20,951

________________

(1)

Sales to affiliates of NRG in the three months ended September 30, 2010 and 2011 represented approximately $179 million and $188 million, respectively, of CenterPoint Houston’s transmission and distribution revenues. Sales to affiliates of Energy Future Holdings Corp. (Energy Future Holdings) in the three months ended September 30, 2010 and 2011 represented approximately $57 million and $58 million, respectively, of CenterPoint Houston’s transmission and distribution revenues. Sales to affiliates of NRG in the nine months ended September 30, 2010 and 2011 represented approximately $447 million and $448 million, respectively, of CenterPoint Houston’s transmission and distribution revenues. Sales to affiliates of Energy Future Holdings in the nine months ended September 30, 2010 and 2011 represented approximately $141 million and $139 million, respectively, of CenterPoint Houston’s transmission and distribution revenues.


(2)	Included in total assets of Other Operations as of December 31, 2010 and September 30, 2011 are pension and other postemployment related regulatory assets of $704 million and $668 million, respectively.

- 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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 131
-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
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+ Details

Subsequent Events	9 Months Ended
Subsequent Events	Sep. 30, 2011
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Subsequent Events On October 26, 2011, CenterPoint Energy’s board of directors declared a regular quarterly cash dividend of $0.1975 per share of common stock payable on December 9, 2011, to shareholders of record as of the close of business on November 16, 2011.

Employee Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2011

Employee Benefit Plans - (Tables) [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

CenterPoint Energy’s net periodic cost includes the following components relating to pension and postretirement benefits:



	Three Months Ended September 30,
	2010						2011
	Pension Benefits ⁽¹⁾			Postretirement Benefits			Pension Benefits ⁽¹⁾			Postretirement Benefits
	(in millions)
Service cost	$	8		$	—		$	8		$	—
Interest cost	26			7			25			5
Expected return on plan assets	(27		)	(2		)	(29		)	(2		)
Amortization of prior service credit	—			—			1			1
Amortization of net loss	15			—			14			—
Amortization of transition obligation	—			2			—			2
Net periodic cost	$	22		$	7		$	19		$	6



	Nine Months Ended September 30,
	2010						2011
	Pension Benefits ⁽¹⁾			Postretirement Benefits			Pension Benefits ⁽¹⁾			Postretirement Benefits
	(in millions)
Service cost	$	24		$	1		$	25		$	1
Interest cost	77			19			75			17
Expected return on plan assets	(82		)	(7		)	(87		)	(7		)
Amortization of prior service credit	2			2			3			3
Amortization of net loss	44			—			42			1
Amortization of transition obligation	—			5			—			5
Net periodic cost	$	65		$	20		$	58		$	20

________________

(1)

- Definition

Tabular disclosure of one or more of the entity's defined benefit pension plans or one or more other defined benefit postretirement plans, separately for pension plans and other postretirement benefit plans including the entity's schedule of fair value of plan assets for defined benefit or other postretirement plans.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5, 6, 7
-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)
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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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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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-Paragraph 5
-Subparagraph d
-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.

+ Details

Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2011

Derivative Instruments [Abstract]

Fair Value of Derivative Instruments Table



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
Indexed debt securities derivative	Current Liabilities	—		232
Total		$	80	$	411

________________


(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 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 $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
Indexed debt securities derivative	Current Liabilities	—		167
Total		$	87	$	278

________________


(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 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.

Income Statement Impact of Derivative Activity Table



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		)
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)	(5		)	88
Total		$	(5	)	$	85

________________


(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		)
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)	—			65
Total		$	(43	)	$	27

________________


(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.

- Definition

Tabular disclosure of the location and amount of gains and losses reported in the statement of financial performance, or when applicable, the statement of financial position. For example, (a) gains and losses recognized in the income statement on derivative instruments designated and qualifying as hedging instruments in fair value hedges and related hedged items designated and qualifying in fair value hedges and (b) gains and losses initially recognized in other comprehensive income on derivative instruments designated and qualifying as cash flow hedges.

+ References + Details

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2011

Fair Value Measurements - (Tables) [Abstract]

Fair value, assets measured on a recurring basis



	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
			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments ⁽¹⁾			December 31, 2010
	(in millions)
Assets
Corporate equities	$	368	$	—	$	—	$	—		$	368
Investments, including money market funds	54		—		—		—			54
Natural gas derivatives	—		73		7		(11		)	69
Total assets	$	422	$	73	$	7	$	(11	)	$	491
Liabilities
Indexed debt securities derivative	$	—	$	232	$	—	$	—		$	232
Natural gas derivatives	8		167		4		(95		)	84
Total liabilities	$	8	$	399	$	4	$	(95	)	$	316

________________


(1)	Amounts represent the impact of legally enforceable master netting agreements that allow CenterPoint Energy 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
			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments ⁽¹⁾			September 30, 2011
	(in millions)
Assets
Corporate equities	$	339	$	—	$	—	$	—		$	339
Investments, including money market funds	54		—		—		—			54
Natural gas derivatives	8		72		7		(23		)	64
Total assets	$	401	$	72	$	7	$	(23	)	$	457
Liabilities
Indexed debt securities derivative	$	—	$	167	$	—	$	—		$	167
Natural gas derivatives	11		96		4		(55		)	56
Total liabilities	$	11	$	263	$	4	$	(55	)	$	223

________________


(1)	Amounts represent the impact of legally enforceable master netting agreements that allow CenterPoint Energy to settle positive and negative positions and also include cash collateral of $32 million posted with the same counterparties.

Assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs



	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, CenterPoint Energy 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, CenterPoint Energy did not have Level 3 purchases or sales.

Estimated fair value of financial instruments, debt instruments



	December 31, 2010				September 30, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	9,303	$	10,071	$	8,850	$	9,870

- Definition

Tabular disclosure of assets, including [financial] instruments measured at fair value that are classified in stockholders' equity, if any, by class that are measured at fair value on a recurring basis. The disclosures contemplated herein include the fair value measurements at the reporting date by 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 (Level 1), significant other observable inputs (Level 2), and significant unobservable inputs (Level 3).

+ References + Details

- Definition

Tabular disclosure of the fair value measurement of assets using significant unobservable inputs (Level 3), a reconciliation of the beginning and ending balances, separately presenting changes during the period attributable to the following: (1) total gains or losses for the period (realized and unrealized), segregating those gains or losses included in earnings (or changes in net assets) and gains or losses recognized in other comprehensive income, 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); (2) purchases, sales, issuances, and settlements (each type disclosed separately); and (3) transfers in and transfers out of Level 3 (for example, transfers due to changes in the observability of significant inputs), by class of asset.

+ References + Details

- Definition

Tabular disclosure of the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments, assets, and liabilities. Such certain disclosures about the financial instruments, assets, and liabilities include: (1) the fair value of the required items together with their carrying amounts (as appropriate) and (2) the methodology and assumptions used in developing such estimates of fair value.

+ 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
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 14
-Subparagraph a
-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
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15
-Subparagraph b-d
-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 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32
-Subparagraph a, c(1), c(2), c(3), d
-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 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 18
-Subparagraph c(2), d, e, f
-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 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 19
-Subparagraph a, b, c(1), d(1)
-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 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 10
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6947722&loc=d3e13433-108611

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=6947722&loc=d3e13467-108611

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=6947722&loc=d3e13476-108611

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 30
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14172-108612

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 820
-SubTopic 10
-Section 50
-Paragraph 2
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6925170&loc=d3e19207-110258

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6447952&loc=d3e13220-108610

+ Details

Goodwill (Tables)

9 Months Ended

Sep. 30, 2011

Goodwill [Line Items]

Schedule of Goodwill [Table Text Block]

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

- 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 (Tables)

9 Months Ended

Sep. 30, 2011

Comprehensive Income [Abstract]

Schedule of Comprehensive Income (Loss) [Table Text Block]

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



	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2010		2011		2010		2011
	(in millions)
Net income	$	123	$	973	$	318	$	1,240
Other comprehensive income:
Adjustment related to pension and other postretirement plans (net of tax of $2, $2, $5 and $5)	2		2		7		7
Reclassification of deferred loss from cash flow hedges realized in net income (net of tax of $-0-, $-0-, $-0- and $-0-)	1		—		1		—
Total	3		2		8		7
Comprehensive income	$	126	$	975	$	326	$	1,247

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

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



	December 31, 2010			September 30, 2011
	(in millions)
Adjustment related to pension and postretirement plans	$	(114	)	$	(107	)
Net deferred loss from cash flow hedges	(3		)	(3		)
Total accumulated other comprehensive loss	$	(117	)	$	(110	)

Short-Term Borrowings and Long-term Debt Credit Facilities (Tables)

9 Months Ended

Sep. 30, 2011

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

Schedule of Line of Credit Facilities [Table Text Block]



	December 31, 2010								September 30, 2011
	Size of Facility		Loans		Letters of Credit		Commercial Paper		Size of Facility		Loans		Letters of Credit		Commercial Paper
CenterPoint Energy	$	1,156	$	—	$	20	$	—	$	1,200	$	—	$	16	$	—
CenterPoint Houston	289		—		4		—		300		—		4		—
CERC Corp.	915		—		—		183		950		—		—		142
Total	$	2,360	$	—	$	24	$	183	$	2,450	$	—	$	20	$	142

Income Taxes (Tables)

9 Months Ended

Sep. 30, 2011

Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]

Summary of Unrecognized Tax Benefits [Table Text Block]

The following table summarizes CenterPoint Energy’s unrecognized tax benefits at December 31, 2010 and September 30, 2011:



	December 31, 2010		September 30, 2011
	(in millions)
Unrecognized tax benefits	$	252	$	52
Portion of unrecognized tax benefits that, if recognized, would reduce the effective income tax rate	17		20
Interest accrued on unrecognized tax benefits	12		—

Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2011

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

The following table reconciles numerators and denominators of CenterPoint Energy’s basic and diluted earnings per share calculations:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2011		2010		2011
	(in millions, except share and per share amounts)
Basic earnings per share calculation:
Income before extraordinary item	$	123	$	386	$	318	$	653
Extraordinary item, net of tax	—		587		—		587
Net income	$	123	$	973	$	318	$	1,240

Weighted average shares outstanding	422,178,000		425,885,000		404,957,000		425,517,000

Basic earnings per share:
Income before extraordinary item	$	0.29	$	0.90	$	0.79	$	1.53
Extraordinary item, net of tax	—		1.38		—		1.38
Net income	$	0.29	$	2.28	$	0.79	$	2.91

Diluted earnings per share calculation:
Net income	$	123	$	973	$	318	$	1,240

Weighted average shares outstanding	422,178,000		425,885,000		404,957,000		425,517,000
Plus: Incremental shares from assumed conversions:
Stock options ⁽¹⁾	548,000		399,000		529,000		377,000
Restricted stock	2,242,000		2,558,000		2,242,000		2,558,000
Weighted average shares assuming dilution	424,968,000		428,842,000		407,728,000		428,452,000

Diluted earnings per share:
Income before extraordinary item	$	0.29	$	0.90	$	0.78	$	1.52
Extraordinary item, net of tax	—		1.37		—		1.37
Net income	$	0.29	$	2.27	$	0.78	$	2.89

________________


(1)	Options to purchase 1,522,444 shares were outstanding for both the three and nine months ended September 30, 2010, but were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares for the respective periods.

Reportable Business Segments (Tables)

9 Months Ended

Sep. 30, 2011

Segment Reporting Information [Line Items]

Financial data for business segments

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)
Electric Transmission & Distribution	$	655	⁽¹⁾	$	—		$	212
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	3			—			4
Eliminations	—			(59		)	—
Consolidated	$	1,908		$	—		$	327



	For the Three Months Ended September 30, 2011
	Revenues from External Customers			Net Intersegment Revenues			Operating Income (Loss)
Electric Transmission & Distribution	$	707	⁽¹⁾	$	—		$	244
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	3			—			4
Eliminations	—			(49		)	—
Consolidated	$	1,881		$	—		$	357



	For the Nine Months Ended September 30, 2010
	Revenues from External Customers			Net Intersegment Revenues			Operating Income		Total Assets as of December 31, 2010
Electric Transmission & Distribution	$	1,699	⁽¹⁾	$	—		$	477	$	9,817
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	9			—			8		2,184			⁽²⁾
Eliminations	—			(178		)	—		(3,130		)
Consolidated	$	6,687		$	—		$	947	$	20,111



	For the Nine Months Ended September 30, 2011
	Revenues from External Customers			Net Intersegment Revenues			Operating Income		Total Assets as of September 30, 2011
Electric Transmission & Distribution	$	1,802	⁽¹⁾	$	—		$	530	$	11,084
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	9			—			6		1,897			⁽²⁾
Eliminations	—			(159		)	—		(3,205		)
Consolidated	$	6,305		$	—		$	1,024	$	20,951

________________

(1)


(2)	Included in total assets of Other Operations as of December 31, 2010 and September 30, 2011 are pension and other postemployment related regulatory assets of $704 million and $668 million, respectively.

- Definition

Tabular disclosure of the profit or loss and total assets for each reportable segment. An entity discloses certain information on each reportable segment if the amounts (a) are included in the measure of segment profit or loss reviewed by the chief operating decision maker or (b) are otherwise regularly provided to the chief operating decision maker, even if not included in that measure of segment profit or loss.

+ References + Details

Employee Benefit Plans (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2011

Sep. 30, 2010

Sep. 30, 2011

Sep. 30, 2010

Defined Benefit Plan Disclosure [Line Items]

Amount of pension and other postemployment benefits deferred as a regulatory asset

$ 2

$ 6

$ 13

$ 18

Pension Plans, Defined Benefit [Member]

Defined Benefit Plan Disclosure [Line Items]

Service cost

^[1]

Interest cost

^[1]

Expected return on plan assets

^[1]

(29)

(27)

(87)

(82)

Amortization of prior service credit

^[1]

Amortization of net loss

^[1]

Amortization of transition obligation

^[1]

Net periodic cost

^[1]

Total contributions to the plans during the period

Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year

Other Postretirement Benefit Plans, Defined Benefit [Member]

Defined Benefit Plan Disclosure [Line Items]

Service cost

Interest cost

Expected return on plan assets

(2)

(7)

Amortization of prior service credit

Amortization of net loss

Amortization of transition obligation

Net periodic cost

$ 7

$ 20

Total contributions to the plans during the period

Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year

$ 18

[1]

Regulatory Matters (Details) $ in Millions	1 Months Ended											3 Months Ended		9 Months Ended		12 Months Ended
Regulatory Matters (Details) $ in Millions	Oct. 31, 2011 USD ($)	Aug. 31, 2011 USD ($)	May 31, 2011 USD ($)	Apr. 30, 2011 USD ($)	Feb. 28, 2011	Nov. 30, 2010 USD ($)	Apr. 30, 2010 USD ($)	Feb. 28, 2010 USD ($)	Oct. 31, 2009 USD ($)	Jul. 31, 2009 USD ($)	May 31, 2009 USD ($)	Sep. 30, 2011 USD ($)	Sep. 30, 2010 USD ($)	Sep. 30, 2011 USD ($)	Sep. 30, 2010 USD ($)	Dec. 31, 2008 USD ($)	Dec. 31, 2005 USD ($)	Mar. 31, 2008	Dec. 31, 2004 USD ($)	Mar. 31, 2004 USD ($)
Resolution of True-Up Appeal [Abstract]
Initial amount of true-up application																				$ 3,700.0
Amount awarded in final true-up order by the Texas Utility Commission																			$ 2,300.0
Net after-tax extraordinary loss												$ 587.0	$ 0.0	$ 587.0	$ 0.0		$ (947.0)
Tax Effect of Extraordinary Item, Gain (Loss)														334.0
Recoverable True-Up Balance												1,695.0		$ 1,695.0
Number of Days to appeal Final Order														20
Number of days subject to appeal from Financing Order issuance														15
Extraordinary Item, Gain (Loss), Gross														$ 921.0
Return on true-up balance												352.0	0.0	352.0	0.0
Return on True-Up Balance after tax														224.0
Equity Return portion of Recoverable True-Up Balance pre-tax												405.0		405.0
Equity Return portion of Recoverable True-Up Balance after-tax												258.0		258.0
Amount of allowed equity return on the true-up balance that has not been recognized												165.0		165.0
Amount of allowed equity return on the true-up balance that was recognized in the period												$ 6.0	$ 5.0	$ 13.0	$ 12.0
Rate Proceedings [Abstract]
Amount of approved base rate increase per year			$ 14.7
Amount of approved decrease on charges to wholesale transmission customers			$ 12.3
Approved rate of return on equity (in hundredths)			10.00%
Approved cost of debt (in hundredths)			6.74%
Approved percentage of capital structure based on equity (in hundredths)			45.00%
Approved percentage of capital structure based on long-term debt (in hundredths)			55.00%
Approved percentage of overall rate of return (in hundredths)			8.21%
Original term of the residential AMS surcharge (in years)			12
Approved reduction in duration of residential AMS surcharge related to the reconciliation plan (in years)			6
Estimated reduction in annual operating income			$ 30.0
Amount of 2010 energy efficiency program costs submitted for reimbursement											$ 10.0
Amount of partial performance bonus approved by the Texas Utility Commission related to 2010 energy efficiency program									$ 8.0
Amount of bonus on 2008 energy efficiency program costs disallowed									2.0
Amount of 2008 energy efficiency program costs submitted for reimbursement									$ 10.0
Approximate amount of costs related to various energy efficiency programs							$ 14.4
Amount of partial performance bonus approved by the Texas Utility Commission related to 2011 energy efficiency program						$ 11.0
Portion of requested amount excluded from recovery which relates to performance bonus						2.0
Portion of requested amount excluded from recovery as relates to lost revenues						$ 1.4
Total amount of application seeking approval of recovery of various costs				$ 44.3
Portion of application seeking recovery of energy efficiency program costs				35.8
Energy Efficiency Performance Bonus		$ 3.6
Under Recovery of 2010 Program Costs		0.5
TCSO Annual Revenue Increase		3.4
Number of DCRF requests allowed per year														1
Number of DCRF filings allowed														4
Payment under Transmission Stipulation	$ 5.6
Number of days after issuance of final appealable order payment made	30
Portion of application seeking an energy efficiency performance bonus based on 2010 program achievements				5.8
Portion of application seeking recovery of lost revenues due to verified and reported 2010 energy savings				2.2
Portion of application seeking for under-recovery of 2010 program costs				0.5
Amount excluded from performance bonus for prior year's program				$ 2.1
Lost Revenues associated with 2010 programs		2.2
Energy Efficiency Costs		$ 35.8
Number of cities in Texas Coast service area (in number of cities)																		47
Approximate number of customers in cities and communities on the outskirts of Houston (in number of customers)																		230,000
Increase in annual revenues from approved rate increases for gas operations in Texas Coast service area																$ 3.5
Number of cities that contested the new rates in the Texas Coast service area (in number of cities)																9
Number of years COSA initially effective					3
Automatic Renewal period for COSA					3
Number of cities in Houston service area (in number of cities)										29
Approximate number of customers in and around Houston (in number of customers)										940,000
Proposed increase in annual revenues from gas operations in Houston service area										$ 20.4
Amount of carrying costs of gas inventory excluded from rate increase										$ 2.0
Amount of approved annual revenue increase in gas operations for the Houston area								$ 5.1
Approved amount of annual surcharge in gas operations to recover Hurricane Ike costs								$ 0.9
Number of years for the surcharge to recover Hurricane Ike costs (in years)								3

Derivative Instruments (Details)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2011

USD ($)

Sep. 30, 2010

USD ($)

Sep. 30, 2011

USD ($)

bcf

Sep. 30, 2010

USD ($)

Dec. 31, 2010

USD ($)

bcf

Derivatives, Fair Value [Abstract]

Derivative assets fair value

$ 87

^[1],[2]

$ 87

^[1],[2]

$ 80

^[3],[4]

Derivative liability fair value

278

^[1],[2]

$ 278

^[1],[2]

$ 411

^[3],[4]

Derivative gross volumes (Bcf)

585

626

Net long position (Bcf) | bcf

Amount of net long position constituted by basis swaps (Bcf) | bcf

Amount of net long position comprised of price stabilization activities of the Natural Gas Distribution business segment (Bcf) | bcf

Total non-trading derivative assets and liabilities net of collateral

$ 8

$ (15)

Collateral netting

Total fair value of the derivative instruments that contain credit risk contingent features that are in a net liability position

107

The aggregate fair value of assets already posted as collateral

Credit Risk Contingent Features assets

Derivative Instruments, Gain (Loss) [Abstract]

Derivative gains and (losses) in the Statements of Consolidated Income

$ (5)

$ (43)

Increased (decreased) natural gas revenues from the unrealized net gains (losses) of derivative instruments

(1)

Increased (decreased) natural gas expense from the unrealized net (gains) losses of derivative instruments

(9)

Net unrealized gain (loss) from derivative instruments

$ 8

Term of normal weather used as the basis for weather hedges (in years)

Losses recognized from weather hedges

$ 6

Natural Gas Contracts [Member] | Gains (Losses) in Revenue [Member]

Derivative Instruments, Gain (Loss) [Abstract]

Derivative gains and (losses) in the Statements of Consolidated Income

Natural Gas Contracts [Member] | Gains (Losses) in Expense: Natural Gas [Member]

Derivative Instruments, Gain (Loss) [Abstract]

Derivative gains and (losses) in the Statements of Consolidated Income

(30)

^[5]

(41)

^[5]

(79)

^[6]

(133)

^[6]

Costs associated with price stabilization activities of the Natural Gas Distribution business segment included in Expenses

(17)

(24)

(79)

(74)

Natural Gas Contracts [Member] | Current Assets [Member]

Derivatives, Fair Value [Abstract]

Derivative assets fair value

^[1],[2],[7]

^[3],[4],[8]

Derivative liability fair value

^[1],[2],[7]

^[3],[4],[8]

Natural Gas Contracts [Member] | Other Assets [Member]

Derivatives, Fair Value [Abstract]

Derivative assets fair value

^[1],[2],[7]

^[3],[4],[8]

Derivative liability fair value

^[1],[2],[7]

^[3],[4],[8]

Natural Gas Contracts [Member] | Current Liabilities [Member]

Derivatives, Fair Value [Abstract]

Derivative assets fair value

^[1],[2],[7]

^[3],[4],[8]

Derivative liability fair value

104

^[1],[2],[7]

104

^[1],[2],[7]

143

^[3],[4],[8]

Natural Gas Contracts [Member] | Other Liabilities [Member]

Derivatives, Fair Value [Abstract]

Derivative assets fair value

^[1],[2],[7]

^[3],[4],[8]

Derivative liability fair value

^[1],[2],[7]

^[3],[4],[8]

Indexed Debt Securities Derivative [Member] | Gains (losses) in Other Income (Expense) [Member]

Derivative Instruments, Gain (Loss) [Abstract]

Derivative gains and (losses) in the Statements of Consolidated Income

$ (5)

$ 0

Indexed Debt Securities Derivative [Member] | Current Liabilities [Member]

Derivatives, Fair Value [Abstract]

Derivative assets fair value

^[1],[2]

^[3],[4]

Derivative liability fair value

$ 167

^[1],[2]

$ 167

^[1],[2]

$ 232

^[3],[4]

[1]	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.
[2]	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.
[3]	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.
[4]	The net of total non-trading derivative assets and liabilities is a $15 million liability 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 $84 million.
[5]	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.
[6]	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.
[7]	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.
[8]	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.

Fair Value Measurements (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2011

Sep. 30, 2010

Sep. 30, 2011

Sep. 30, 2010

Dec. 31, 2010

Assets

Corporate equities

$ 339

$ 368

Investments, including money market funds

Natural gas derivatives, assets

Total assets

457

491

Liabilities

Indexed debt securities derivative

167

232

Natural gas derivatives, liabilities

Total liabilities

223

316

Cash collateral posted with counterparties

Fair value measurement using significant unobservable input (level 3) reconciliation [Roll Forward]

Beginning balance

$ 5

$ (6)

Total unrealized gains or losses:

Included in earnings

(1)

Included in regulatory assets

(1)

Total settlements, gross:

Included in earnings

(1)

^[1]

(2)

^[1]

(3)

^[2]

(1)

^[2]

Included in regulatory assets

^[2]

Ending balance

Amount of total gains for the period included in earnings

(1)

$ 1

$ 4

Carrying Amount [Member]

Liabilities

Long-term debt

8,850

9,303

Fair Value [Member]

Liabilities

Long-term debt

9,870

10,071

Fair Value, Inputs, Level 1 [Member]

Assets

Corporate equities

339

368

Investments, including money market funds

Natural gas derivatives, assets

Total assets

401

422

Liabilities

Indexed debt securities derivative

Natural gas derivatives, liabilities

Total liabilities

Fair Value, Inputs, Level 2 [Member]

Assets

Corporate equities

Investments, including money market funds

Natural gas derivatives, assets

Total assets

Liabilities

Indexed debt securities derivative

167

232

Natural gas derivatives, liabilities

167

Total liabilities

263

399

Fair Value, Inputs, Level 3 [Member]

Assets

Corporate equities

Investments, including money market funds

Natural gas derivatives, assets

Total assets

Liabilities

Indexed debt securities derivative

Natural gas derivatives, liabilities

Total liabilities

Netting Adjustments [Member]

Assets

Corporate equities

^[3]

^[4]

Investments, including money market funds

^[3]

^[4]

Natural gas derivatives, assets

(23)

^[3]

(23)

^[3]

(11)

^[4]

Total assets

(23)

^[3]

(23)

^[3]

(11)

^[4]

Liabilities

Indexed debt securities derivative

^[3]

^[4]

Natural gas derivatives, liabilities

(55)

^[3]

(55)

^[3]

(95)

^[4]

Total liabilities

$ (55)

^[3]

$ (55)

^[3]

$ (95)

^[4]

[1]	During both the three months ended September 30, 2010 and 2011, CenterPoint Energy did not have Level 3 purchases or sales.
[2]	During both the nine months ended September 30, 2010 and 2011, CenterPoint Energy did not have Level 3 purchases or sales.
[3]	Amounts represent the impact of legally enforceable master netting agreements that allow CenterPoint Energy to settle positive and negative positions and also include cash collateral of $32 million posted with the same counterparties.
[4]	Amounts represent the impact of legally enforceable master netting agreements that allow CenterPoint Energy to settle positive and negative positions and also include cash collateral of $84 million posted with the same counterparties.

Goodwill (Details) - USD ($) $ in Millions	Sep. 30, 2011	Dec. 31, 2010
Goodwill Schedule [Line Items]
Goodwill	$ 1,696	$ 1,696
Natural Gas Distribution [Member]
Goodwill Schedule [Line Items]
Goodwill	746	746
Interstate Pipelines [Member]
Goodwill Schedule [Line Items]
Goodwill	579	579
Competitive Natural Gas Sales and Services [Member]
Goodwill Schedule [Line Items]
Goodwill	335	335
Field Services [Member]
Goodwill Schedule [Line Items]
Goodwill	25	25
Other Operations [Member]
Goodwill Schedule [Line Items]
Goodwill	$ 11	$ 11

- Definition

Carrying amount as of the balance sheet date, which is the cumulative amount paid and (if applicable) the fair value of any noncontrolling interest in the acquiree, adjusted for any amortization recognized prior to the adoption of any changes in generally accepted accounting principles (as applicable) and for any impairment charges, in excess of the fair value of net assets acquired in one or more business combination transactions.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-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 142
-Paragraph 43
-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
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 68
-Subparagraph l
-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 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6388280&loc=d3e13770-109266

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6905597&loc=d3e13816-109267

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 72
-Subparagraph d
-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 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-Clause 1
-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 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 34
-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.

+ Details

Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
Comprehensive Income (Details) - USD ($) $ in Millions	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Net income	$ 973	$ 123	$ 1,240	$ 318
Other comprehensive income:
Adjustment related to pension and other postretirement plans (net of tax of $1, $1, $3 and $3)	2	2	7	7
Reclassification of deferred loss from cash flow hedges realized in net income (net of tax of $-0-, $-0-, $-0- and $-0-)	0	1	0	1
Total	2	3	7	8
Comprehensive income	975	126	1,247	326
Adjustment related to pension and postretirement plans	(107)		(107)		$ (114)
Net deferred loss from cash flow hedges	(3)		(3)		(3)
Total accumulated other comprehensive loss	(110)		(110)		$ (117)
Tax effects on adjustment to pension and other postretirement plans	2	2	5	5
Tax effect on reclassification of deferred loss from cash flow hedges realized in net income	$ 0	$ 0	$ 0	$ 0

Capital Stock (Details) - $ / shares	Sep. 30, 2011	Dec. 31, 2010
Capital Stock (Details) [Abstract]
Capital stock shares authorized (in shares)	1,020,000,000
Common stock shares authorized (in shares)	1,000,000,000
Common stock shares par value (in dollars per share)	$ 0.01
Cumulative preferred stock shares authorized (in shares)	20,000,000
Cumulative preferred stock par value (in dollars per share)	$ 0.01
Total common stock issued (in shares)	425,919,358	424,746,343
Total common stock outstanding (in shares)	425,919,192	424,746,177
Treasury stock (in shares)	166	166

Short-Term Borrowings and Long-term Debt (Details) $ in Millions	1 Months Ended	9 Months Ended
	Jan. 31, 2011 USD ($)	Sep. 30, 2011 USD ($)	Dec. 31, 2010 USD ($)
Debt Instrument [Line Items]
Receivable facility maximum advance capacity			$ 160
Total short term borrowings		$ 84	53
Long-term Debt [Abstract]
Total credit facility amount		2,450	2,360
Line of Credit Facility, Amount Outstanding		0	0
Amount of outstanding letters of credit		20	24
Long-term Commercial Paper		142	183
Long term debt		$ 8,497	9,001
Consecutive Period for System Restoration Costs to Exceed $100 million (in months)		12
CERC Corp [Member]
Long-term Debt [Abstract]
Amount of senior notes issued (CERC Corp. senior notes)			550
Bank loans due 2016 [Member] \| CenterPoint Houston [Member]
Debt Instrument [Line Items]
Length of revolving credit facility (in years)		5
Long-term Debt [Abstract]
Total credit facility amount		$ 300	289
Line of Credit Facility, Amount Outstanding		0	0
Amount of outstanding letters of credit		4	4
Long-term Commercial Paper		$ 0	0
Revolving credit facility borrowing rate		LIBOR plus 150
Percentage on limitation of debt to total capitalization under covenant (in hundredths)		65.00%
Bank loans due 2016 [Member] \| CenterPoint Energy [Member]
Debt Instrument [Line Items]
Length of revolving credit facility (in years)		5
Long-term Debt [Abstract]
Total credit facility amount		$ 1,200	1,156
Line of Credit Facility, Amount Outstanding		0	0
Amount of outstanding letters of credit		16	20
Long-term Commercial Paper		$ 0	0
Revolving credit facility borrowing rate		London Interbank Offered Rate (LIBOR) plus 175
Debt to EBITDA covenant ratio, before amendment		5
Debt to EBITDA covenant ratio, amendment		5.5
System restoration costs threshold for increase in permitted debt to EBITDA covenant ratio		$ 100
Bank loans due 2016 [Member] \| CERC Corp [Member]
Debt Instrument [Line Items]
Length of revolving credit facility (in years)		5
Long-term Debt [Abstract]
Total credit facility amount		$ 950	915
Line of Credit Facility, Amount Outstanding		0	0
Amount of outstanding letters of credit		0	0
Long-term Commercial Paper		$ 142	183
Revolving credit facility borrowing rate		LIBOR plus 150
Percentage on limitation of debt to total capitalization under covenant (in hundredths)		65.00%
CERC Corp. receivables facility [Member]
Debt Instrument [Line Items]
Total short term borrowings			0
Product Financing Arrangement [Member]
Debt Instrument [Line Items]
Total short term borrowings		$ 84	$ 53
Senior notes issued, due 2021 (CERC Corp. senior notes) [Member] \| CERC Corp [Member]
Long-term Debt [Abstract]
Amount of senior notes issued (CERC Corp. senior notes)	$ 250
Debt Instrument, Interest Rate, Stated Percentage (in hundredths)	4.50%
Senior notes issued, due 2011 (CERC Corp. senior notes) [Member] \| CERC Corp [Member]
Long-term Debt [Abstract]
Extinguishment of debt, principal amount		$ 550
Debt Instrument, Interest Rate, Stated Percentage (in hundredths)		7.75%
Senior notes issued, due 2041 (CERC Corp. senior notes) [Member] \| CERC Corp [Member]
Long-term Debt [Abstract]
Amount of senior notes issued (CERC Corp. senior notes)	$ 300
Debt Instrument, Interest Rate, Stated Percentage (in hundredths)	5.85%
Senior notes issued, due 2021 (CERC exchange offer) [Member] \| CERC Corp [Member]
Long-term Debt [Abstract]
Amount of senior notes issued (CERC Corp. senior notes)	$ 343
Debt Instrument, Interest Rate, Stated Percentage (in hundredths)	4.50%
Amount of cash consideration provided related to CERC exchange offer	$ 114
Unamortized debt issuance cost	$ 58
Senior notes 2013 to 2037 [Member] \| CERC Corp [Member]
Long-term Debt [Abstract]
Extinguishment of debt, principal amount		$ 397
Debt Instrument, Interest Rate, Stated Percentage (in hundredths)	7.875%

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
Income Taxes (Details) - USD ($) $ in Millions	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010	Mar. 31, 2010
Effective tax rate (in hundredths)	35.00%	38.00%	36.00%	41.00%
Amount of non-cash recorded to income tax expense as result of change in tax law				$ 21
Decrease in accrued interest for tax reserves related to potential normalization violation			$ 9
Amount of reduction to deferred tax assets due to actuarially determined net present value of lost future health care deductions						$ 32
Amount of adjustment to regulatory assets due to actuarially determined net present value of lost future health care deductions						$ 11
Unrecognized tax benefits	$ 52		52		$ 252
Portion of unrecognized tax benefits that, if recognized, would reduce the effective income tax rate	20		20		17
Interest accrued on unrecognized tax benefits	0		0		$ 12
Decrease in unrecognized tax benefits reltated to potential normalization violaton	200		200
Reduction to liability for unrecognized tax benefits recorded	279
Reduction in unrecognized tax benefits related to balance as of 12/31/2010	211
Reduction in unrecognized tax benefits related to balance as of 6/30/2011	68
Increase in deferred tax liability	268
Decrease in income tax expense for the release of accrued interest expense	11
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound	16		16
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound	$ 35		$ 35
Period of time for possible decrease in unrecognized tax benefits (in months)			12

Commitments and Contingencies (Details)	9 Months Ended
Commitments and Contingencies (Details)	Sep. 30, 2011 USD ($) bcf MMcf
Recorded Unconditional Purchase Obligation
2011	$ 181,000,000
2012	499,000,000
2013	498,000,000
2014	388,000,000
2015	235,000,000
After 2015	$ 410,000,000
Legal Environmental And Other Regulatory Matters Legal Matters Gas Market Manipulation Cases Abstract
Recovery of compensatory damages sought by plaintiffs	in excess of $1 billion
Approximate number of gas market manipulation lawsuits naming CenterPoint and/or Reliant Energy (in number of lawsuits)	30
Number of gas market manipulation lawsuits pending for CenterPoint and its affiliates (in number of lawsuits)	2
Number of gas market mismeasurement lawsuits pending for CenterPoint and its affiliates (in number of lawsuits)	2
Approximate number of pipeline companies named in the mismeasurement lawsuits (in number of companies)	245
Number of gas measurement lawsuits seeking class certification and has four amendments (in number of cases)	1
Number of times gas measurement lawsuit was amended (in number of amendments)	4
Number of years the plaintiffs claim the defendants have engaged in the systematic mismeasurement of natural gas (in years)	25
Number of CenterPoint subsidiaries dismissed from the claims of the plaintiff (in number of claims)	2
Number of sites where remediation is complete, other than ongoing operations (in number of sites)	2
Number of remaining sites in the Minnesota service territory (in number of sites)	5
Number of the remaining sites in the Minnesota service territory where the company believes it has no liability (in number of sites)	2
Amount accrued for remediation of Minnesota sites (in number of sites)	$ 13,000,000
Minimum estimated remediation costs for the Minnesota sites	6,000,000
Maximum estimated remediation costs for the Minnesota sites	$ 41,000,000
Minimum years of remediation for the Minnesota sites (in years)	30
Maximum years of remediation for the Minnesota sites (in years)	50
Annual amount included in rates to fund normal on-going remediation costs	$ 285,000
Amount collected from insurance companies to be used for future environmental remediation	5,400,000
Approximate amount of undiscounted maximum potential demand charges under the transportation contracts	100,000,000
Approximate amount of collateral posted as security on transportation contracts	$ 7,000,000
Magnolia Gathering System [Member]
Schedule of Capital Expansion Projects
Expanded natural gas capacity per day (in million cubic feet) \| MMcf	700
Amount spent on original project scope for expansion	$ 320,000,000
Number of years lapsed under volumne commitment	second
Years of volume commitment (in number of years)	10
Additional natural gas capacity per day under the expansion election (in million cubic feet) \| MMcf	200
Total capacity per day of system after expansion (in million cubic feet) \| MMcf	900
Total costs of additional expansion	$ 52,000,000
Potential additional natural gas capacity per day under potential additional expansion election (in million cubic feet) \| MMcf	800
Total capacity per day of system after potential additional expansion (in billion cubic feet) \| bcf	1.7
Total estimatted costs of potential additional expansion	$ 240,000,000
Olympia Gathering System [Member]
Schedule of Capital Expansion Projects
Expanded natural gas capacity per day (in million cubic feet) \| MMcf	600
Amount spent on original project scope for expansion	$ 390,000,000
Number of years lapsed under volumne commitment	second
Years of volume commitment (in number of years)	10
Additional natural gas capacity per day under the expansion election (in million cubic feet) \| MMcf	520
Total System Capacity After Expansion \| bcf	1.1
Total costs of additional expansion	$ 200,000,000
Estimated remaining costs to complete expansion	$ 35,000,000

Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2005
Basic earnings per share calculation: [Abstract]
Income (Loss) from Operations before Extraordinary Items	$ 386	$ 123	$ 653	$ 318
Extraordinary Item, net of tax	587	0	587	0	$ (947)
Net income	$ 973	$ 123	$ 1,240	$ 318
Weighted average shares outstanding	425,885,000	422,178,000	425,517,000	404,957,000
Basic Earnings Per Share:
Income Before Extraordinary Item	$ 0.90	$ 0.29	$ 1.53	$ 0.79
Extraordinary Item, net of tax	1.38	0.00	1.38	0.00
Net Income	$ 2.28	$ 0.29	$ 2.91	$ 0.79
Diluted earnings per share calculation: [Abstract]
Net income	$ 973	$ 123	$ 1,240	$ 318
Weighted average shares outstanding	425,885,000	422,178,000	425,517,000	404,957,000
Plus: Incremental shares from assumed conversions:
Incremental Common Shares Attributable to Share-based Payment Arrangements	399,000	548,000	377,000	529,000
Incremental Common Shares Attributable To Restricted Stock	2,558,000	2,242,000	2,558,000	2,242,000
Weighted Average Shares Outstanding	428,842,000	424,968,000	428,452,000	407,728,000
Diluted earnings per share:
Income Before Extraordinary Item	$ 0.90	$ 0.29	$ 1.52	$ 0.78
Extraordinary Item, net of tax	1.37	0.00	1.37	0.00
Earnings Per Share, Diluted	$ 2.27	$ 0.29	$ 2.89	$ 0.78
Outstanding shares with the options to purchase not included in the computation of diluted earnings per share (in shares)		1,522,444		1,522,444

Reportable Business Segments (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2011

Sep. 30, 2010

Sep. 30, 2011

Sep. 30, 2010

Dec. 31, 2010

Segment Reporting Information [Line Items]

Revenues from External Customers

$ 1,881

$ 1,908

$ 6,305

$ 6,687

Intersegment Revenues

Operating Income

357

327

1,024

947

Total Assets

20,951

$ 20,111

Electric Transmission and Distribution [Member]

Segment Reporting Information [Line Items]

Revenues from External Customers

^[1]

707

655

1,802

1,699

Intersegment Revenues

Operating Income

244

212

530

477

Total Assets

11,084

9,817

Sales to subsidiaries of NRG Energy, Inc.

188

179

448

447

Sales to subsidiaries of Energy Future Holdings Corp.

139

141

Natural Gas Distribution [Member]

Segment Reporting Information [Line Items]

Revenues from External Customers

379

395

2,034

2,390

Intersegment Revenues

Operating Income

(2)

(4)

153

145

Total Assets

4,379

4,575

Competitive Natural Gas Sales and Services [Member]

Segment Reporting Information [Line Items]

Revenues from External Customers

580

638

1,858

2,032

Intersegment Revenues

Operating Income

(10)

Total Assets

1,108

1,190

Interstate Pipelines [Member]

Segment Reporting Information [Line Items]

Revenues from External Customers

104

136

328

352

Intersegment Revenues

104

Operating Income

196

207

Total Assets

3,826

3,672

Field Services [Member]

Segment Reporting Information [Line Items]

Revenues from External Customers

108

274

205

Intersegment Revenues

Operating Income

136

Total Assets

1,862

1,803

Other Operations [Member]

Segment Reporting Information [Line Items]

Revenues from External Customers

Intersegment Revenues

Operating Income

Total Assets

^[2]

1,897

2,184

Pension and other postemployment related regulatory assets included in total assets of Other Operations

668

704

Reconciling Eliminations [Member]

Segment Reporting Information [Line Items]

Revenues from External Customers

Intersegment Revenues

(49)

(59)

(159)

(178)

Operating Income

$ 0

Total Assets

$ (3,205)

$ (3,130)

[1]

[2]

Included in total assets of Other Operations as of December 31, 2010 and September 30, 2011 are pension and other postemployment related regulatory assets of $704 million and $668 million, respectively.

Subsequent Events (Details) - Dividend Declared [Member]	9 Months Ended
	Sep. 30, 2011 USD ($)
Subsequent Event [Line Items]
Subsequent Event, Date	Oct. 26, 2011
Subsequent Event, Amount	$ 0.1975