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Document And Entity Information - USD ($) $ in Millions	12 Months Ended
Document And Entity Information - USD ($) $ in Millions	Dec. 31, 2011	Jun. 30, 2011
Document and Entity Information [Abstract]
Entity Registrant Name	CENTERPOINT ENERGY RESOURCES CORP
Entity Central Index Key	0001042773
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float		$ 0
Entity Common Stock, Shares Outstanding	1,000
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2011

CONDENSED STATEMENTS OF CONSOLIDATED INCOME (Unaudited) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income Statement [Abstract]
Revenues	$ 6,102	$ 6,569	$ 6,257
Expenses:
Natural gas	4,055	4,574	4,371
Operation and maintenance	964	913	922
Depreciation and amortization	262	248	229
Taxes other than income taxes	159	167	166
Total	5,440	5,902	5,688
Operating Income	662	667	569
Other Income (Expense):
Interest and other finance charges	(190)	(208)	(213)
Equity in earnings of unconsolidated affiliates	30	29	15
Other, net	1	(1)	5
Total	(159)	(180)	(193)
Income Before Income Taxes	503	487	376
Income tax expense	187	187	146
Net Income	$ 316	$ 300	$ 230

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Statement of Income and Comprehensive Income [Abstract]
Net Income	$ 316	$ 300	$ 230
Other comprehensive income (loss):
Adjustment to pension and other postretirement plans (net of tax of $3, $1 and $1)	(2)	(1)	(2)
Other comprehensive loss	(2)	(1)	(2)
Comprehensive income	$ 314	$ 299	$ 228

- Definition

The change in equity [net assets] of a business enterprise during a period from transactions and other events and circumstances from non-owner sources which are attributable to the reporting entity. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, but excludes any and all transactions which are directly or indirectly attributable to that ownership interest in subsidiary equity which is not attributable to the parent.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 8, 9, 10, 11, 12, 13, 14
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-Name Accounting Research Bulletin (ARB)
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-Appendix A

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-URI http://asc.fasb.org/extlink&oid=6518256

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-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6519514

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+ Details

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References

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-Name Emerging Issues Task Force (EITF)
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-Publisher SEC
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-Number 210
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+ Details

- Definition

This element represents Other Comprehensive Income or Loss, Net of Tax, for the period attributable to the parent entity. Includes deferred gains or losses on qualifying hedges, unrealized holding gains or losses on available-for-sale securities, minimum pension liability, and cumulative translation adjustment.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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+ Details

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Current Assets:
Cash and cash equivalents	$ 1	$ 1
Accounts receivable, net	542	603
Accrued unbilled revenue	253	270
Accounts and notes receivable - affiliated companies	17	19
Inventory	273	304
Non-trading derivative assets	87	54
Taxes receivable	1	63
Deferred income tax assets	8	48
Prepaid expenses and other current assets	122	208
Total current assets	1,304	1,570
Property, plant and equipment, net	7,030	6,636
Other Assets:
Goodwill	1,696	1,696
Non-trading derivative assets	20	15
Investment in unconsolidated affiliates	472	468
Other	165	153
Total other assets	2,353	2,332
Total Assets	10,687	10,538
Current Liabilities:
Short-term borrowings	62	53
Accounts payable	427	573
Accounts and notes payable - affiliated companies	419	541
Taxes accrued	82	73
Interest accrued	48	51
Customer deposits	74	76
Non-trading derivative liabilities	46	68
Other	157	255
Total current liabilities	1,315	1,690
Other Liabilities:
Accumulated deferred income taxes, net	1,420	1,319
Non-trading derivative liabilities	6	16
Benefit obligations	108	100
Regulatory liabilities	597	572
Other	232	140
Total other liabilities	2,363	2,147
Long-term Debt	2,919	2,925
Total stockholder's equity	4,090	3,776
Total Liabilities and Stockholder's Equity	$ 10,687	$ 10,538

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Cash Flows from Operating Activities:
Net Income	$ 316	$ 300	$ 230
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	262	248	229
Deferred income taxes	144	208	247
Amortization of deferred financing costs	13	9	9
Write-down of natural gas inventory	11	6	6
Equity in earnings of unconsolidated affiliates, net of distributions	8	13	(3)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net.	67	120	238
Accounts receivable/payable, affiliates	(14)	6	3
Inventory	20	(52)	231
Taxes receivable	62	(16)	(47)
Accounts payable	(101)	(35)	(160)
Fuel cost over (under) recovery	(70)	(9)	(5)
Interest and taxes accrued	6	5	(34)
Non-trading derivatives, net	(10)	(5)	29
Margin deposits, net.	34	7	116
Other current assets	11	(20)	46
Other current liabilities	(12)	(14)	57
Other assets	(3)	(7)	1
Other liabilities	22	(21)	(14)
Other, net	3	(21)	0
Net cash provided by operating activities	769	722	1,179
Cash Flows from Investing Activities:
Capital expenditures	(644)	(917)	(690)
(Increase) decrease in notes receivable from unconsolidated affiliates	0	0	323
Investment in unconsolidated affiliates	(12)	(18)	(115)
Other, net	10	20	(3)
Net cash used in investing activities	(646)	(915)	(485)
Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings, net	9	(2)	(98)
Revolving credit facility, net	0	0	(926)
Proceeds from commercial paper, net	102	183	0
Payments of long-term debt	(606)	(45)	(7)
Cash paid for debt exchange	(58)	0	0
Proceeds from long-term debt	550	0	0
Increase (decrease) in notes payable to affiliates	(106)	57	432
Dividends to parent	0	0	(100)
Debt issuance costs	(14)	0	0
Other, net	0	0	5
Net cash provided by (used in) financing activities	(123)	193	(694)
Net Decrease in Cash and Cash Equivalents	0	0	0
Cash and Cash Equivalents at Beginning of the Year	1	1	1
Cash and Cash Equivalents at End of the Year	1	1	1
Cash Payments:
Interest, net of capitalized interest	177	191	203
Income taxes (refunds), net	(20)	141	(31)
Non-cash transactions:
Accounts payable related to capital expenditures	$ 53	$ 98	$ 53

CONDENSED STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY - USD ($) $ in Millions	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
Balance (in shares) at Dec. 31, 2008		1,000
Balance at Dec. 31, 2008		$ 0	$ 2,416	$ 935
Dividends to parent	$ 100			(100)
Net Income	230			230
Balance (in shares) at Dec. 31, 2009		1,000
Balance at Dec. 31, 2009	3,477	$ 0	2,416	1,065	$ (4)
Adjustment to pension and postretirement plans					(4)
Dividends to parent	0			0
Net Income	300			300
Balance (in shares) at Dec. 31, 2010		1,000
Balance at Dec. 31, 2010	3,776	$ 0	2,416	1,365	(5)
Adjustment to pension and postretirement plans					(5)
Dividends to parent	0			0
Net Income	316			316
Balance (in shares) at Dec. 31, 2011		1,000
Balance at Dec. 31, 2011	$ 4,090	$ 0	$ 2,416	$ 1,681	7
Adjustment to pension and postretirement plans					$ (7)

- Definition

The total of net gain (loss), prior service cost (credit), and transition assets (obligations), as well as minimum pension liability if still remaining, included in accumulated other comprehensive income associated with a defined benefit pension or other postretirement plan(s) because they have yet to be recognized as components of net periodic benefit cost.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 26
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+ Details

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References

+ Details

Background	12 Months Ended
Background	Dec. 31, 2011
Background and Basis of Presentation [Abstract]
Background and Basis of Presentation	Background CenterPoint Energy Resources Corp. (CERC Corp., and, together with its subsidiaries, CERC), owns and operates natural gas distribution systems in six states. Subsidiaries of CERC Corp. own interstate natural gas pipelines and gas gathering systems and provide various ancillary services. A wholly owned subsidiary of CERC offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities. CERC Corp. is a Delaware corporation. CERC Corp. is an indirect wholly owned subsidiary of CenterPoint Energy, Inc. (CenterPoint Energy), a public utility holding company. For a description of CERC'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

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Significant Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

Summary of Significant Accounting Policies

(a) Use of Estimates

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

(b) Principles of Consolidation

The accounts of CERC Corp. and its wholly owned and majority owned subsidiaries are included in CERC's consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. CERC uses the equity method of accounting for investments in entities in which CERC has an ownership interest between 20% and 50% and exercises significant influence. CERC’s investments in unconsolidated affiliates include a 50% ownership interest in Southeast Supply Header, LLC (SESH) which owns and operates a 274-mile interstate natural gas pipeline and a 50% interest in Waskom Gas Processing Company (Waskom), a Texas general partnership, which owns and operates a natural gas processing plant and natural gas gathering assets. During 2009, CERC invested $137 million in SESH and received a capital distribution of $23 million from SESH. During 2010, CERC invested $20 million in Waskom. Other investments, excluding marketable securities, are carried at cost.

CERC records revenue for natural gas sales and services under the accrual method and these revenues are recognized upon delivery to customers. Natural gas sales not billed by month-end are accrued based upon estimated purchased gas volumes, estimated lost and unaccounted for gas and currently effective tariff rates. The Interstate Pipelines and Field Services business segments record revenues as transportation and processing services are provided.

(d) Long-lived Assets and Intangibles

CERC records property, plant and equipment at historical cost. CERC expenses repair and maintenance costs as incurred. CERC periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, compared to the carrying value of the assets.

(e) Regulatory Assets and Liabilities

CERC applies the guidance for accounting for regulated operations to the Natural Gas Distribution business segment and to portions of the Interstate Pipelines business segment. CERC’s rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. As of December 31, 2010 and 2011, these removal costs of $545 million and $573 million, respectively, are classified as regulatory liabilities in the Consolidated Balance Sheets. In addition, a portion of the amount of removal costs that relate to asset retirement obligations has been reclassified from a regulatory liability to an asset retirement liability in accordance with accounting guidance for conditional asset retirement obligations.

(f) Depreciation and Amortization Expense

Depreciation and amortization is computed using the straight-line method based on economic lives or regulatory-mandated recovery periods. Amortization expense includes amortization of regulatory assets and other intangibles.

(g) Capitalization of Interest and Allowance for Funds Used During Construction

Interest and allowance for funds used during construction (AFUDC) are capitalized as a component of projects under construction and are amortized over the assets’ estimated useful lives once the assets are placed in service. AFUDC represents the composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction for subsidiaries that apply the guidance for accounting for regulated operations. During 2009, 2010 and 2011, CERC capitalized interest and AFUDC of $2 million, $7 million and less than $1 million, respectively.

(h) Income Taxes

CERC is included in the consolidated income tax returns of CenterPoint Energy. CERC calculates its income tax provision on a separate return basis under a tax sharing agreement with CenterPoint Energy. CERC uses the asset and liability method of accounting for deferred income taxes in accordance with accounting guidance for income taxes. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. A valuation allowance is established against deferred tax assets for which management believes realization is not considered to be more likely than not. Current federal and certain state income taxes are payable to or receivable from CenterPoint Energy. CERC recognizes interest and penalties as a component of income tax expense.

(i) Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are net of an allowance for doubtful accounts of $25 million and $24 million at December 31, 2010 and 2011, respectively. The provision for doubtful accounts in CERC’s Statements of Consolidated Income for 2009, 2010 and 2011 was $35 million, $30 million and $25 million, respectively.

(j) Inventory

Inventory consists principally of materials and supplies and natural gas. Materials and supplies are valued at the lower of average cost or market. Materials and supplies are recorded to inventory when purchased and subsequently charged to expense or capitalized to plant when installed. Natural gas inventories of CERC’s Competitive Natural Gas Sales and Services business segment are also primarily valued at the lower of average cost or market. Natural gas inventories of CERC’s Natural Gas Distribution business segment are primarily valued at weighted average cost. During 2010 and 2011, CERC recorded $6 million and $11 million, respectively, in write-downs of natural gas inventory to the lower of average cost or market.



	December 31,
	2010		2011
	(in millions)
Materials and supplies	$	93	$	86
Natural gas	211		187
Total inventory	$	304	$	273

(k) Derivative Instruments

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

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

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

(l) Environmental Costs

CERC expenses or capitalizes environmental expenditures, as appropriate, depending on their future economic benefit. CERC expenses amounts that relate to an existing condition caused by past operations that do not have future economic benefit. CERC records undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.

(m) Statements of Consolidated Cash Flows

For purposes of reporting cash flows, CERC considers cash equivalents to be short-term, highly-liquid investments with maturities of three months or less from the date of purchase.

(n) New Accounting Pronouncements

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

In June 2011, the FASB issued new accounting guidance on the presentation of comprehensive income. The new guidance is intended to improve the overall quality of financial reporting by increasing the prominence of items reported in other comprehensive income and aligning the presentation of other comprehensive income in financial statements prepared in accordance with U.S. GAAP with those prepared in accordance with IFRS. The new guidance requires an entity to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. This new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Adoption of this new guidance did not have an impact on CERC's financial position, results of operations or cash flows.

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

In December 2011, the FASB issued new accounting guidance that will require disclosure of information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The new disclosure requirements mandate that entities disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as disclosure of collateral received and posted in connection with these instruments. This new guidance is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods therein, with retrospective application required. CERC expects that the adoption of this new guidance will not have a material impact on its financial position, results of operations or cash flows.

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

(o) Other Current Assets and Liabilities

Included in other current assets on the Consolidated Balance Sheets at December 31, 2010 and 2011 were $23 million and $17 million, respectively, of margin deposits and $99 million and $63 million, respectively of under-recovered gas cost. Included in other current liabilities on the Consolidated Balance Sheets at December 31, 2010 and 2011 were $94 million and $14 million, respectively, of over-recovered gas cost.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2011

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Disclosure [Text Block]

Property, Plant and Equipment

(a) Property, Plant and Equipment

Property, plant and equipment includes the following:



	Weighted Average Useful Lives	December 31,
	(Years)	2010		2011
		(in millions)
Natural Gas Distribution	32	$	3,642	$	3,959
Competitive Natural Gas Sales and Services	27	71		76
Interstate Pipelines	57	2,594		2,675
Field Services	46	1,583		1,754
Other property	13	49		55
Total		7,939		8,519
Accumulated depreciation and amortization:
Natural Gas Distribution		954		1,069
Competitive Natural Gas Sales and Services		16		20
Interstate Pipelines		265		302
Field Services		43		72
Other property		25		26
Total accumulated depreciation and amortization		1,303		1,489
Property, plant and equipment, net		$	6,636	$	7,030

(b) Depreciation and Amortization

The following table presents depreciation and amortization expense for 2009, 2010 and 2011:



	Year Ended December 31,
	2009		2010		2011
	(in millions)
Depreciation expense	$	211	$	232	$	244
Amortization expense	18		16		18
Total depreciation and amortization expense	$	229	$	248	$	262

A reconciliation of the changes in the asset retirement obligation (ARO) liability is as follows (in millions):



	December 31,
	2010			2011
Beginning balance	$	60		$	58
Accretion expense	4			3
Revisions in estimates of cash flows	(6		)	71
Ending balance	$	58		$	132

The decrease of $6 million in the ARO from the revision of estimate in 2010 is primarily attributable to changes in the estimated lives of some of the assets underlying the liability. The increase of $71 million in the ARO from the revision of estimate in 2011 is primarily attributable to an increase in the disposal costs used in the cash flow assumptions. There were no material additions or settlements during the years ended December 31, 2010 and 2011.

- Definition

The entire disclosure for long-lived, physical assets that are used in the normal conduct of business to produce goods and services and not intended for resale. Examples include land, buildings, machinery and equipment, and other types of furniture and equipment including, but not limited to, office equipment, furniture and fixtures, and computer equipment and software. This disclosure may include property plant and equipment accounting policies and methodology, a schedule of property, plant and equipment gross, additions, deletions, transfers and other changes, depreciation, depletion and amortization expense, net, accumulated depreciation, depletion and amortization expense and useful lives, income statement disclosures, assets held for sale and public utility disclosures.

+ References + Details

Goodwill

12 Months Ended

Dec. 31, 2011

Goodwill [Abstract]

Goodwill

Goodwill by reportable business segment as of December 31, 2010 and 2011 is as follows (in millions):



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

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

CERC performed the test at July 1, 2011, its annual impairment testing date, and determined that no impairment charge for goodwill was required. Other intangibles were not material as of December 31, 2010 and 2011.

- 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

Regulatory Matters

12 Months Ended

Dec. 31, 2011

Regulatory Matters [Abstract]

Regulatory Matters

(a) Regulatory Assets and Liabilities

The following is a list of regulatory assets/liabilities reflected on CERC's Consolidated Balance Sheets as of December 31, 2010 and 2011:



	December 31,
	2010			2011
	(in millions)
Regulatory assets in other long-term assets (1)	$	68		$	97
Regulatory liabilities	(572		)	(597		)
Net	$	(504	)	$	(500	)

________________


(1)	Regulatory assets that are not earning a return were not material at December 31, 2010 and 2011.

(b) Rate Proceedings

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 (COSA) mechanism both in 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 COSA mechanism to the Texas Third Court of Appeals in Austin, Texas. In October 2011, the Texas Third Court of Appeals reversed the district court's ruling. In December 2011, the Texas Third Court of Appeals denied a motion for rehearing. In February 2012, parties opposed to the decision appealed to the Texas Supreme Court. CERC does not expect the outcome of this matter to have a material adverse impact on its financial condition, results of operations or cash flows. The COSA mechanism 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 COSA 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 COSA 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 COSA 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. 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 certain other adjustments. The Railroad Commission also approved a surcharge of $0.9 million per year to recover over three years costs associated with damage caused by Hurricane Ike. 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.

CERC has a 50% ownership interest in SESH which owns and operates a 274-mile interstate natural gas pipeline. In 2009, SESH discontinued the use of guidance for accounting for regulated operations, which resulted in CERC recording its share of the effects of such write-offs of SESH’s regulatory assets through non-cash pre-tax charges for the year ended December 31, 2009 of $16 million. These non-cash charges are reflected in equity in earnings of unconsolidated affiliates in the Statements of Consolidated Income. The related tax benefits of $6 million are reflected in the Income Tax Expense line in the Statements of Consolidated Income.

Employee Benefit Plans

12 Months Ended

Dec. 31, 2011

Employee Benefit Plans [Abstract]

Employee Benefit Plans

(a) Pension Plans

Substantially all of CERC’s employees participate in CenterPoint Energy’s qualified non-contributory defined benefit pension plan. Under the cash balance formula, participants accumulate a retirement benefit based upon 5% of eligible earnings, which increased from 4% effective January 1, 2009, and accrued interest.

CenterPoint Energy’s funding policy is to review amounts annually in accordance with applicable regulations in order to achieve adequate funding of projected benefit obligations. Pension expense is allocated to CERC based on covered employees. This calculation is intended to allocate pension costs in the same manner as a separate employer plan. Assets of the plan are not segregated or restricted by CenterPoint Energy’s participating subsidiaries. CERC recognized pension expense of $45 million, $34 million and $30 million for the years ended December 31, 2009, 2010 and 2011, respectively.

In addition to the plan, CERC participates in CenterPoint Energy’s non-qualified benefit restoration plans, which allow participants to receive the benefits to which they would have been entitled under CenterPoint Energy’s non-contributory pension plan except for federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated. The expense associated with the non-qualified pension plan was $2 million, $1 million and $2 million for the years ended December 31, 2009, 2010 and 2011, respectively.

(b) Savings Plan

CERC participates in CenterPoint Energy’s qualified savings plan, which includes a cash or deferred arrangement under Section 401(k) of the Internal Revenue Code of 1986, as amended. Under the plan, participating employees may contribute a portion of their compensation, on a pre-tax or after-tax basis, generally up to a maximum of 50% of eligible compensation. CERC matches 100% of the first 6% of each employee’s compensation contributed. The matching contributions are fully vested at all times. CenterPoint Energy allocates to CERC the savings plan benefit expense related to CERC’s employees. Savings plan benefit expense was $15 million, $16 million and $17 million for the years ended December 31, 2009, 2010, and 2011, respectively.

CERC’s employees participate in CenterPoint Energy’s plans, which provide certain healthcare and life insurance benefits for retired employees on both a contributory and non-contributory basis. Employees become eligible for these benefits if they have met certain age and service requirements at retirement, as defined in the plans. Under plan amendments effective in early 1999, healthcare benefits for future retirees were changed to limit employer contributions for medical coverage. Such benefit costs are accrued over the active service period of employees. CERC is required to fund a portion of its obligations in accordance with rate orders. All other obligations are funded on a pay-as-you-go basis.

The net postretirement benefit cost includes the following components:



	Year Ended December 31,
	2009			2010			2011
	(in millions)
Service cost — benefits earned during the period	$	1		$	1		$	1
Interest cost on accumulated benefit obligation	8			7			6
Expected return on plan assets	(1		)	(1		)	(1		)
Amortization of prior service cost	2			2			2
Amortization of net loss	—			—			1
Net postretirement benefit cost	$	10		$	9		$	9

CERC used the following assumptions to determine net postretirement benefit costs:



	Year Ended December 31,
	2009		2010		2011
Discount rate	6.90	%	5.70	%	5.20	%
Expected return on plan assets	4.50	%	4.50	%	4.50	%

In determining net periodic benefits cost, CERC uses fair value, as of the beginning of the year, as its basis for determining expected return on plan assets.

Following are reconciliations of CERC’s beginning and ending balances of its postretirement benefit plan’s benefit obligation, plan assets and funded status for 2010 and 2011. The measurement dates for plan assets and obligations were December 31, 2010 and 2011.



	Year Ended December 31,
	2010			2011
	(in millions)
Change in Benefit Obligation
Accumulated benefit obligation, beginning of year	$	121		$	112
Service cost	1			1
Interest cost	7			6
Benefits paid	(22		)	(14		)
Participant contributions	4			4
Medicare reimbursement	—			2
Early retiree reinsurance program reimbursement	—			1
Actuarial loss	1			6
Accumulated benefit obligation, end of year	$	112		$	118
Change in Plan Assets
Plan assets, beginning of year	$	21		$	22
Benefits paid	(22		)	(14		)
Employer contributions	18			9
Participant contributions	4			4
Actual investment return	1			1
Plan assets, end of year	$	22		$	22
Amounts Recognized in Balance Sheets
Current liabilities-other	$	(7	)	$	(7	)
Other liabilities-benefit obligations	(83		)	(89		)
Net liability, end of year	$	(90	)	$	(96	)
Actuarial Assumptions
Discount rate	5.20		%	4.80		%
Expected long-term return on assets	4.50		%	3.10		%
Healthcare cost trend rate assumed for the next year	8.50		%	8.00		%
Prescription cost trend rate assumed for the next year	8.50		%	8.00		%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)	5.50		%	5.50		%
Year that the healthcare rate reaches the ultimate trend rate	2017			2017
Year that the prescription drug rate reaches the ultimate trend rate	2017			2017

The discount rate assumption was determined by matching the accrued cash flows of CenterPoint Energy’s plans against a hypothetical yield curve of high-quality corporate bonds represented by a series of annualized individual discount rates from one-half to 99 years.

The expected rate of return assumption was developed by a weighted-average return analysis of the targeted asset allocation of CenterPoint Energy’s plans and the expected real return for each asset class, based on the long-term capital market assumptions, adjusted for investment fees and diversification effects, in addition to expected inflation.

For measurement purposes, healthcare and prescription costs are assumed to increase to 8.00% during 2012, after which this rate decreases until reaching the ultimate trend rate of 5.50% in 2017, except for the 2013 rate which is expected to increase to 9.00% in anticipation of the healthcare exchanges being introduced to the market in 2014.

Amounts recognized in accumulated other comprehensive loss consist of the following:



	Year Ended December 31,
	2010			2011
	(in millions)
Unrecognized actuarial loss	$	24		$	28
Unrecognized prior service cost	6			4
	30			32
Less deferred tax benefit (1)	(25		)	(25		)
Net amount recognized in accumulated other comprehensive loss	$	5		$	7

________________


(1)	CERC’s postretirement benefit obligation is reduced by the impact of previously non-taxable government subsidies under the Medicare Prescription Drug Act. Because the subsidies were non-taxable, the temporary difference used in measuring the deferred tax impact was determined on the unrecognized losses excluding such subsidies.

The changes in plan assets and benefit obligations recognized in other comprehensive income during 2011 are as follows:



	Postretirement Benefits
	(in millions)
Net loss	$	4
Amortization of prior service cost	(2		)
Total recognized in other comprehensive income	$	2

The total expense recognized in net periodic costs and other comprehensive income was $11 million for postretirement benefits for the year ended December 31, 2011.

The amounts in accumulated other comprehensive loss expected to be recognized as components of net periodic benefit cost during 2012 are as follows:



	Postretirement Benefits
	(in millions)
Unrecognized actuarial loss	$	1
Unrecognized prior service cost	2
Amounts in accumulated other comprehensive loss to be recognized as net periodic cost	$	3

Assumed healthcare cost trend rates have a significant effect on the reported amounts for CERC’s postretirement benefit plans. A 1% change in the assumed healthcare cost trend rate would have the following effects:



	1% Increase		1% Decrease
	(in millions)
Effect on the postretirement benefit obligation	$	4	$	(3	)
Effect on the total of service and interest cost	—		—

In managing the investments associated with the postretirement benefit plan, CERC’s objective is to preserve and enhance the value of plan assets while maintaining an acceptable level of volatility. These objectives are expected to be achieved through an investment strategy that manages liquidity requirements while maintaining a long-term horizon in making investment decisions and efficient and effective management of plan assets.

As part of the investment strategy discussed above, CERC adopted and maintained the following asset allocation ranges for its postretirement benefit plan:



Domestic equity securities	15-25%
International equity securities	2-12%
Debt securities	68-78%
Cash	0-2%

The fair values of CERC’s postretirement plan assets at December 31, 2010 and 2011, by asset category are as follows:



	Fair Value Measurements at December 31, 2010 (in millions)
	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Mutual funds (1)	$	22	$	22	$	—	$	—
Total	$	22	$	22	$	—	$	—

________________


(1)	70% of the amount invested in mutual funds was in fixed income securities; 22% was in U.S. equities and 8% was in international equities.



	Fair Value Measurements at December 31, 2011 (in millions)
	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Mutual funds (1)	$	22	$	22	$	—	$	—
Total	$	22	$	22	$	—	$	—

________________


(1)	72% of the amount invested in mutual funds was in fixed income securities; 22% was in U.S. equities and 6% was in international equities.

CERC expects to contribute $9 million to its postretirement benefits plan in 2012. The following benefit payments are expected to be paid by the postretirement benefit plan:



	Postretirement Benefit Plan
	Benefit Payments		Medicare Subsidy Receipts
	(in millions)
2012	$	11	$	(2	)
2013	11		(2		)
2014	11		(2		)
2015	12		(3		)
2016	12		(3		)
2017-2021	66		(18		)

(d) Postemployment Benefits

CERC participates in CenterPoint Energy’s plan that provides postemployment benefits for former or inactive employees, their beneficiaries and covered dependents, after employment but before retirement (primarily healthcare and life insurance benefits for participants in the long-term disability plan). CERC recorded postemployment benefit income of $-0-, $1 million and expense of $4 million for the years ended December 31, 2009, 2010 and 2011, respectively. Amounts relating to postemployment benefits included in “Benefit Obligations” in the accompanying Consolidated Balance Sheets at December 31, 2010 and 2011, were $11 million and $12 million, respectively.

(e) Other Non-Qualified Plans

CERC participates in CenterPoint Energy’s deferred compensation plans that provide benefits payable to directors, officers and certain key employees or their designated beneficiaries at specified future dates, upon termination, retirement or death. Benefit payments are made from the general assets of CERC. During 2009, 2010 and 2011, the benefit expense relating to these plans was less than $1 million each year. Amounts relating to deferred compensation plans included in “Benefit Obligations” in the accompanying Consolidated Balance Sheets at December 31, 2010 and 2011 were $2 million and $3 million, respectively.

(f) Other Employee Matters

As of December 31, 2011, approximately 29% of CERC's employees are subject to collective bargaining agreements. Collective bargaining agreements with each of the following bargaining units, which collectively cover approximately 15% of CERC's employees, are scheduled to expire in 2012: United Steel Workers (USW) Local 13-227, Office and Professional Employees International Union (OPEIU) Local 12 Metro, OPEIU Local 12 Mankato, and USW Local 13-1. CERC believes it has good relationships with these bargaining units and expects to negotiate new agreements in 2012.

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-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 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph 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 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph h
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-Number 132R
-Paragraph 5
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Paragraph 518
-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
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-Name Statement of Financial Accounting Standard (FAS)
-Number 87
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-Number 03-2
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-Name Accounting Principles Board Opinion (APB)
-Number 30
-Paragraph 26
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-Number 132R
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-Number FAS88
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+ Details

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2011
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions CERC participates in a “money pool” through which it can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. CERC had money pool borrowings of $489 million and $383 million at December 31, 2010 and 2011, respectively, which are included in accounts and notes payable —affiliated companies in the Consolidated Balance Sheets. At December 31, 2011, CERC’s money pool borrowings had a weighted-average interest rate of 0.07%. CERC had net interest expense related to affiliate borrowings of less than $1 million, $2 million and less than $1 million for the years ended December 31, 2009, 2010 and 2011, respectively. CenterPoint Energy provides some corporate services to CERC. The costs of services have been charged directly to CERC using methods that management believes are reasonable. These methods include negotiated usage rates, dedicated asset assignment and proportionate corporate formulas based on operating expenses, assets, gross margin, employees and a composite of assets, gross margin and employees. These charges are not necessarily indicative of what would have been incurred had CERC not been an affiliate of CenterPoint Energy. Amounts charged to CERC for these services were $154 million, $154 million and $164 million for 2009, 2010 and 2011, respectively, and are included primarily in operation and maintenance expenses. In 2009, CERC paid dividends of $100 million to its parent. No dividends were paid to the parent in 2010 and 2011.

- Definition

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

+ References

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

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Article 3A
-Section 04
-Paragraph b

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-Number 57
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+ Details

Derivative Instruments

12 Months Ended

Dec. 31, 2011

Derivative Instruments [Abstract]

Derivative Instruments

(a) Non-Trading Activities

Derivative Instruments. CERC enters into certain derivative instruments to manage physical commodity price risks and does not engage in proprietary or speculative commodity trading. These financial instruments do not qualify or are not designated as cash flow or fair value hedges.

During the year ended December 31, 2009, CERC recorded decreased natural gas revenues from unrealized net losses of $80 million and decreased natural gas expense from unrealized net gains of $57 million, a net unrealized loss of $23 million. During the year ended December 31, 2010, CERC recorded increased natural gas revenues from unrealized net gains of $18 million and increased natural gas expense from unrealized net losses of $14 million, a net unrealized gain of $4 million. During the year ended December 31, 2011, CERC recorded increased natural gas revenues from unrealized net gains of $38 million and increased natural gas expense from unrealized net losses of $30 million, a net unrealized gain of $8 million.

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

In 2009, 2010 and 2011, CERC entered into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its financial position and cash flows for the respective winter heating seasons. The swaps were based on ten-year normal weather. During the years ended December 31, 2009, 2010 and 2011, CERC recognized losses of $6 million, $-0- and less than $1 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 Statements of Consolidated Income.

(b) Derivative Fair Values and Income Statement Impacts

The following tables present information about CERC’s derivative instruments and hedging activities. The first two tables provide a balance sheet overview of CERC’s Derivative Assets and Liabilities as of December 31, 2010 and 2011, while the last table provides a breakdown of the related income statement impacts for the years ending December 31, 2010 and 2011.



Fair Value of Derivative Instruments
	December 31, 2010
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value (2) (3)		Derivative Liabilities Fair Value (2) (3)
		(in millions)
Natural gas contracts (1)	Current Assets	$	55	$	1
Natural gas contracts (1)	Other Assets	15		—
Natural gas contracts (1)	Current Liabilities	10		143
Natural gas contracts (1)	Other Liabilities	—		35
Total		$	80	$	179

________________


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


(2)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 626 billion cubic feet (Bcf) or a net 72 Bcf long position. Of the net long position, basis swaps constitute 63 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment constitute 26 Bcf.


(3)	The net of total non-trading derivative assets and liabilities is a $15 million liability as shown on CERC’s 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
	December 31, 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	$	88	$	1
Natural gas contracts (1)	Other Assets	20		—
Natural gas contracts (1)	Current Liabilities	15		110
Natural gas contracts (1)	Other Liabilities	—		13
Total		$	123	$	124

________________


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


(2)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 633 Bcf or a net 84 Bcf long position. Of the net long position, basis swaps constitute 74 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment constitute 6 Bcf.


(3)	The net of total non-trading derivative assets and liabilities is a $55 million asset as shown on CERC’s Consolidated Balance Sheets, and is comprised of the natural gas contracts derivative assets and liabilities separately shown above offset by collateral netting of $56 million.

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



Income Statement Impact of Derivative Activity
		Year Ended December 31,
Total derivatives not designated as hedging instruments	Income Statement Location	2010			2011
		(in millions)
Natural gas contracts	Gains (Losses) in Revenue	$	90		$	102
Natural gas contracts (1)	Gains (Losses) in Expense: Natural Gas	(165		)	(144		)
Total		$	(75	)	$	(42	)

________________


(1)	The Gains (Losses) in Expense: Natural Gas includes $(115) million and $(107) million of costs in 2010 and 2011, respectively, associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered through purchased gas adjustments.

CERC enters into financial derivative contracts containing material adverse change provisions. These provisions could require CERC to post additional collateral if the Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc. credit ratings of CERC 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 2011 was $107 million and $39 million, respectively. The aggregate fair value of assets that are already posted as collateral was $31 million and less than $1 million, respectively, at December 31, 2010 and 2011. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at December 31, 2010 and 2011, $76 million and $38 million, respectively, of additional assets would be required to be posted as collateral.

(d) Credit Quality of Counterparties

In addition to the risk associated with price movements, credit risk is also inherent in CERC’s non-trading derivative activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The following table shows the composition of counterparties to the non-trading derivative assets of CERC as of December 31, 2010 and 2011 (in millions):



	December 31, 2010				December 31, 2011
	Investment Grade(1)		Total		Investment Grade(1)		Total
Energy marketers	$	5	$	8	$	1	$	7
Financial institutions	1		1		—		—
Retail end users (2)	—		60		—		100
Total	$	6	$	69	$	1	$	107

________________

(1)

“Investment grade” is primarily determined using publicly available credit ratings and considering credit support (such as parent company guaranties) and collateral, which encompass cash and standby letters of credit. For unrated counterparties, CERC determines a synthetic credit rating by performing financial statement analysis and considering contractual rights and restrictions and collateral.


(2)	Retail end users represent customers who have contracted to fix the price of a portion of their physical gas requirements for future periods.

- 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
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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+ Details

Fair Value Measurements

12 Months Ended

Dec. 31, 2011

Fair Value Measurements [Abstract]

Fair Value Measurements

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

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

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

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the level in the fair value hierarchy within which the fair value measurement in its entirety falls has been determined based on the lowest level input that is significant to the fair value measurement in its entirety. Unobservable inputs reflect CERC’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. CERC develops these inputs based on the best information available, including CERC’s own data. A market approach is utilized to value CERC’s Level 3 assets or liabilities.

CERC determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes any transfers between levels at the end of the reporting period. CERC also recognizes purchases of Level 3 financial assets and liabilities at their fair value at the end of the reporting period.

The following tables present information about CERC’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of December 31, 2010 and 2011, and indicate the fair value hierarchy of the valuation techniques utilized by CERC to determine such fair value.



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments ⁽¹⁾			Balance as of December 31, 2010
	(in millions)
Assets
Corporate equities	$	1	$	—	$	—	$	—		$	1
Investments, including money market funds	11		—		—		—			11
Natural gas derivatives	—		73		7		(11		)	69
Total assets	$	12	$	73	$	7	$	(11	)	$	81
Liabilities
Natural gas derivatives	$	8	$	167	$	4	$	(95	)	$	84
Total liabilities	$	8	$	167	$	4	$	(95	)	$	84

________________


(1)	Amounts represent the impact of legally enforceable master netting agreements that allow CERC to settle positive and negative positions and also include cash collateral of $84 million posted with the same counterparties.



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments ⁽¹⁾			Balance as of December 31, 2011
	(in millions)
Assets
Corporate equities	$	1	$	—	$	—	$	—		$	1
Investments, including money market funds	11		—		—		—			11
Natural gas derivatives	1		112		10		(16		)	107
Total assets	$	13	$	112	$	10	$	(16	)	$	119
Liabilities
Natural gas derivatives	$	19	$	101	$	4	$	(72	)	$	52
Total liabilities	$	19	$	101	$	4	$	(72	)	$	52

________________


(1)	Amounts represent the impact of legally enforceable master netting agreements that allow CERC to settle positive and negative positions and also include cash collateral of $56 million posted with the same counterparties.

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



	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	Year Ended December 31,
	2009			2010			2011
	(in millions)
Beginning balance	$	(58	)	$	(6	)	$	3
Total unrealized gains or (losses):
Included in earnings	(1		)	4			6
Included in regulatory assets	(16		)	(1		)	—
Total settlements:
Included in earnings	3			(2		)	(3		)
Included in regulatory assets	66			8			—
Total purchases	—			—			2
Net transfers out of Level 3	—			—			(2		)
Ending balance	$	(6	)	$	3		$	6
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	1		$	4		$	5

Estimated Fair Value of Financial Instruments

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



	December 31, 2010				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	2,925	$	3,158	$	2,919	$	3,272

- Definition

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

+ References

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

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32
-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 157
-Paragraph 33
-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 6
-Footnote 4
-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 Accounting Standards Codification
-Topic 820
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6925170&loc=d3e19207-110258

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 820
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6925170&loc=d3e19190-110258

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 820
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6925170&loc=d3e19279-110258

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 820
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6925170&loc=d3e19296-110258

+ Details

Short-term Borrowings and Long-term Debt

12 Months Ended

Dec. 31, 2011

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

Short-term Borrowings and Long-term Debt



	December 31, 2010					December 31, 2011
	Long-Term			Current(1)		Long-Term			Current(1)
	(in millions)
Short-term borrowings:
Inventory financing	$	—		$	53	$	—		$	62
Total short-term borrowings	—			53		—			62
Long-term debt:
Senior notes 5.95% to 7.875% due 2013 to 2037	2,747			—		2,693			—
Commercial paper (2)	183			—		285			—
Unamortized discount and premium	(5		)	—		(59		)	—
Total long-term debt	2,925			—		2,919			—
Total debt	$	2,925		$	53	$	2,919		$	62

________________


(1)	Includes amounts due or exchangeable within one year of the date noted.


(2)	Classified as long-term debt because the termination date of the facility that backstops the commercial paper is more than one year from the date noted.

(a)Short-term Borrowings

Receivables Facility. CERC's receivables facility terminated pursuant to its terms on September 14, 2011. As of December 31, 2010 the facility size was $160 million and there were no advances under the receivables facility.

Inventory Financing. In October 2009, Gas Operations entered into asset management agreements associated with its utility distribution service in Arkansas, north Louisiana and Oklahoma that extend through 2015. 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 $62 million as of December 31, 2010 and 2011, respectively.


(b)	Long-term Debt

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

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

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



December 31, 2010								December 31, 2011
Size of Facility		Loans		Letters of Credit		Commercial Paper		Size of Facility		Loans		Letters of Credit		Commercial Paper
$	915	$	—	$	—	$	183	$	950	$	—	$	—	$	285

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

CERC Corp. was in compliance with all debt covenants as of December 31, 2011.

Maturities. CERC’s consolidated maturities of long-term debt are $-0- in 2012, $365 million in 2013, $160 million in 2014, $-0- in 2015 and $610 million in 2016.

- 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

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Income Taxes

The components of CERC’s income tax expense were as follows:



	Year Ended December 31,
	2009			2010			2011
	(in millions)
Current income tax expense (benefit):
Federal	$	(107	)	$	(38	)	$	34
State	6			17			9
Total current expense (benefit)	(101		)	(21		)	43
Deferred income tax expense (benefit):
Federal	226			234			140
State	21			(26		)	4
Total deferred expense	247			208			144
Total income tax expense	$	146		$	187		$	187

A reconciliation of the expected federal income tax expense using the federal statutory income tax rate to the actual income tax expense and resulting effective income tax rate is as follows:



	Year Ended December 31,
	2009			2010			2011
	(in millions)
Income before income taxes	$	376		$	487		$	503
Federal statutory income tax rate	35		%	35		%	35		%
Expected federal income tax expense	132			170			176
Increase (decrease) in tax expense resulting from:
State income tax expense (benefit), net of federal income tax	18			(6		)	9
Increase (decrease) in settled and uncertain income tax positions	(1		)	5			1
Tax law change in deductibility of retiree health care costs	—			18			—
Other, net	(3		)	—			1
Total	14			17			11
Total income tax expense	$	146		$	187		$	187
Effective tax rate	38.8		%	38.4		%	37.2		%

CERC recorded a net reduction in state income tax expense of approximately $20 million related to lower blended state tax rates and a reduction of the deferred tax liability recorded in December 2011.

CERC recorded a non-cash, $19 million increase to income tax expense in 2010 as a result of a change in tax law upon the enactment in March 2010 of the Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act of 2010. The change in tax law, which becomes effective for tax years beginning after December 31, 2012, eliminates the tax deductibility of the portion of retiree health care costs that are reimbursed by Medicare Part D subsidies. Based upon the actuarially determined net present value of lost future retiree health care deductions related to the subsidies, CERC reduced its deferred tax asset by approximately $22 million in March 2010. The portion of the reduction that CERC believes will be recovered through the regulatory process, or approximately $2 million, was recorded as an adjustment to regulatory assets. The regulatory assets were also increased in March 2010 by approximately $1 million related to the recovery of CERC’s income taxes. The remaining $19 million of the reduction in CERC’s deferred tax asset was recorded as a charge to income tax expense in the first quarter of 2010.

In December 2010, certain subsidiaries of CERC were restructured in order to achieve a more tax-efficient reporting structure. As a result of the restructuring, CERC recorded a net reduction in income tax expense of approximately $24 million related to the remeasurement of accumulated deferred income taxes. The net reduction in income tax expense is comprised of a decrease in state income tax expense, net of federal income tax, totaling approximately $29 million and an increase in income tax expense of approximately $5 million related to uncertain income tax positions.

The state income tax expense of $18 million for 2009 included a benefit of approximately $8 million, net of federal income tax, related to adjustments in prior years’ state estimates.

The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities were as follows:



	December 31,
	2010			2011
	(in millions)
Deferred tax assets:
Current:
Allowance for doubtful accounts	$	10		$	9
Deferred gas costs	33			—
Other	5			(1		)
Total current deferred tax assets	48			8
Non-current:
Employee benefits	55			57
Loss and credit carryforwards	19			238
Other	30			60
Total non-current deferred tax assets before valuation allowance	104			355
Valuation allowance	(3		)	(3		)
Total non-current deferred tax assets, net of valuation allowance	101			352
Total deferred tax assets, net of valuation allowance	149			360
Deferred tax liabilities:
Non-current:
Depreciation	$	1,397		$	1,696
Regulatory assets, net	14			17
Other	9			59
Total non-current deferred tax liabilities	1,420			1,772
Accumulated deferred income taxes, net	$	1,271		$	1,412

Tax Attribute Carryforwards and Valuation Allowance. At December 31, 2011, CERC has approximately $614 million of federal net operating loss carryforwards which begin to expire in 2030 and $349 million of state net operating loss carryforwards which expire in various years between 2012 and 2031. CERC has approximately $244 million of state capital loss carryforwards which expire in 2017 for which a valuation allowance has been established. CERC has established a valuation allowance of $3 million for state net operating loss carryforwards and state capital loss carryforwards.

Uncertain Income Tax Positions. The following table reconciles the beginning and ending balance of CERC’s unrecognized tax benefits:



	December 31,
	2009			2010			2011
	(in millions)
Balance, beginning of year	$	(12	)	$	6		$	11
Tax Positions related to prior years:
Additions	18			—			(1		)
Reductions	—			(2		)	(3		)
Tax Positions related to current year:
Additions	2			7			1
Settlements	(2		)	—			—
Balance, end of year	$	6		$	11		$	8

The net increase in the total amount of unrecognized tax benefits during 2010 is primarily related to the remeasurement of accumulated deferred income taxes associated with the restructuring of certain subsidiaries of CERC.

CERC had no unrecognized tax benefits that, if recognized, would reduce the effective income tax rate for 2009. CERC had approximately $5 million and $6 million of unrecognized tax benefits that, if recognized, would reduce the effective income tax rate for 2010 and 2011, respectively. CERC recognizes interest and penalties as a component of income tax expense. CERC recognized approximately $1 million of interest benefit, $0.4 million of interest expense and $0.4 million of interest expense on uncertain income tax positions during 2009, 2010 and 2011, respectively. CERC accrued $4.5 million and $4.1 million of interest receivable on uncertain income tax positions at December 31, 2010 and 2011, respectively.

It is reasonably possible over the next 12 months that the total amount of unrecognized tax benefits could decrease by as much as $1 million or increase by as much as $17 million primarily as a result of the acceptance by the Internal Revenue Service (IRS) of a refund claim related to the timing of a deduction for debt issuance costs.

Tax Audits and Settlements. CenterPoint Energy’s consolidated federal income tax returns have been audited and settled through the 2005 tax year. CenterPoint Energy has a tentative closing agreement for tax years 2006 and 2007 with the IRS's Appeals Division pending review by the Joint Committee on Taxation. CenterPoint Energy is currently under examination by the IRS for tax years 2008 and 2009 and is at various stages of the examination process. CERC has considered the effects of these examinations in its accrual for settled issues and liability for uncertain income tax positions as of December 31, 2011.

- 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
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32718-109319

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 6: 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.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32537-109319

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32559-109319

+ Details

Commitments and Contingencies

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies [Abstract]

Commitments and Contingencies

(a) Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to CERC’s Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in CERC’s Consolidated Balance Sheets as of December 31, 2010 and 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 December 31, 2011, minimum payment obligations for natural gas supply commitments are approximately $467 million in 2012, $449 million in 2013, $353 million in 2014, $219 million in 2015, $151 million in 2016 and $251 million after 2016.

(b) Asset Management Agreements

Gas Operations has entered into asset management agreements associated with its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and Texas. Generally, these asset management agreements are contracts between Gas Operations and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these agreements, Gas Operations agreed to release transportation and storage capacity to other parties to manage gas storage, supply and delivery arrangements for Gas Operations and to use the released capacity for other purposes when it is not needed for Gas Operations. Gas Operations is compensated by the asset manager through payments made over the life of the agreements based in part on the results of the asset optimization. Under the provisions of these asset management agreements, Gas Operations has an obligation to purchase its winter storage requirements from the asset manager. The agreements have varying terms, the longest of which expires in 2016.

The following table sets forth information concerning CERC’s obligations under non-cancelable long-term operating leases at December 31, 2011, which primarily consist of rental agreements for building space, data processing equipment, compression equipment and rights of way (in millions):



2012	$	14
2013	9
2014	6
2015	4
2016	4
2017 and beyond	15
Total	$	52

Total lease expense for all operating leases was $36 million, $76 million and $42 million in 2009, 2010 and 2011, respectively.

(d) Long-Term Gas Gathering and Treating Agreements

CenterPoint Energy Field Services, LLC (CEFS) has entered into long-term agreements with an indirect wholly-owned subsidiary of Encana Corporation (Encana) and an indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide gathering and treating services for their natural gas production from certain Haynesville Shale and Bossier Shale formations in Texas and Louisiana.

Under the long-term agreements, Encana or Shell may elect to require CEFS to expand the capacity of its gathering systems by up to an additional 1.3 Bcf per day. CEFS estimates that the cost to expand the capacity of its gathering systems by an additional 1.3 Bcf per day would be as much as $440 million. Encana and Shell would provide incremental volume commitments in connection with an election to expand system capacity.

(e) 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. 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 review of the district court's decision has now passed.

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

Environmental Matters

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

At December 31, 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 provided for the inclusion in rates of approximately $285,000 annually to fund normal on-going remediation costs. As of December 31, 2011, CERC had collected $5.5 million from insurance companies to be used to mitigate future environmental costs.

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 does not expect the ultimate outcome of these investigations will have a material adverse impact on the financial condition, results of operations or cash flows.

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

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

Other Proceedings

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

(f) 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 $88 million as of December 31, 2011. Market conditions in the fourth quarters of 2010 and 2011 required posting of security under the agreement, and GenOn posted approximately $7 million in collateral in December 2010 and an additional $21 million of collateral 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

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-Number 14
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+ Details

Unaudited Quarterly Information

12 Months Ended

Dec. 31, 2011

Unaudited Quarterly Information [Abstract]

Quarterly Financial Information [Text Block]

Unaudited Quarterly Information

Summarized quarterly financial data is as follows:



	Year Ended December 31, 2010
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter (1)
	(in millions)
Revenues	$	2,538	$	1,191	$	1,250	$	1,590
Operating income	248		101		111		207
Net income	106		33		42		119



	Year Ended December 31, 2011
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(in millions)
Revenues	$	2,095	$	1,228	$	1,171	$	1,608
Operating income	260		114		111		177
Net income	133		47		43		93

________________


(1)	During the fourth quarter of 2010, CERC recorded a $21 million gain on the sale of non-strategic gathering assets by its Field Services business segment. CERC also recorded a $24 million decrease in income tax expense related to the effects of re-measuring accumulated deferred income taxes associated with the restructuring of certain subsidiaries.

- Definition

The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished.

+ References + Details

Reportable Business Segments

12 Months Ended

Dec. 31, 2011

Reportable Business Segments [Abstract]

Reportable Business Segments

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

CERC’s reportable business segments include the following: Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines, Field Services and Other Operations. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers. Competitive Natural Gas Sales and Services represents CenterPoint Energy’s non-rate regulated gas sales and services operations. 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. The Other Operations business segment includes unallocated corporate costs and inter-segment eliminations.

Long-lived assets include net property, plant and equipment, net goodwill and other intangibles and equity investments in unconsolidated subsidiaries. Intersegment sales are eliminated in consolidation.

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



	Revenues from External Customers		Inter-segment Revenues			Depreciation and Amortization		Operating Income (Loss)			Total Assets			Expenditures for Long- Lived Assets
As of and for the year ended December 31, 2009:
Natural Gas Distribution	$	3,374	$	10		$	161	$	204		$	4,535		$	165
Competitive Natural Gas Sales and Services	2,215		15			4		21			1,176			2
Interstate Pipelines (1)	456		142			48		256			3,484			176
Field Services (2)	212		29			15		94			1,045			348
Other	—		—			1		(6		)	800			—
Reconciling Eliminations	—		(196		)	—		—			(1,256		)	—
Consolidated	$	6,257	$	—		$	229	$	569		$	9,784		$	691
As of and for the year ended December 31, 2010:
Natural Gas Distribution	$	3,199	$	14		$	166	$	231		$	4,575		$	202
Competitive Natural Gas Sales and Services	2,617		34			4		16			1,190			2
Interstate Pipelines (1)	464		137			52		270			3,672			102
Field Services (2)	289		49			25		151			1,803			668
Other	—		—			1		(1		)	659			—
Reconciling Eliminations	—		(234		)	—		—			(1,361		)	—
Consolidated	$	6,569	$	—		$	248	$	667		$	10,538		$	974

As of and for the year ended December 31, 2011:
Natural Gas Distribution	$	2,823	$	18		$	166	$	226		$	4,636		$	295
Competitive Natural Gas Sales and Services	2,488		23			5		6			1,089			5
Interstate Pipelines (1)	421		132			54		248			3,867			98
Field Services (2)	370		42			37		189			1,894			201
Other	—		—			—		(7		)	660			—
Reconciling Eliminations	—		(215		)	—		—			(1,459		)	—
Consolidated	$	6,102	$	—		$	262	$	662		$	10,687		$	599

________________

(1)

Interstate Pipelines recorded equity income of $7 million, $19 million, and $21 million (including $33 million related to pre-operating allowance for funds used during construction during 2009) in the years ended December 31, 2009, 2010 and 2011, respectively, from its 50% interest in SESH, a jointly-owned pipeline. These amounts are included in Equity in earnings of unconsolidated affiliates under the Other Income (Expense) caption. Interstate Pipelines’ investment in SESH was $422 million, $413 million and $409 million as of December 31, 2009, 2010 and 2011, respectively, and is included in Investment in unconsolidated affiliates.

(2)

Field Services recorded equity income of $8 million, $10 million and $9 million for the years ended December 31, 2009, 2010 and 2011, respectively, from its 50% interest in a jointly-owned gas processing plant. These amounts are included in Equity in earnings of unconsolidated affiliates under the Other Income (Expense) caption. Field Services’ investment in the jointly-owned gas processing plant was $40 million, $55 million and $63 million as of December 31, 2009, 2010 and 2011, respectively, and is included in Investment in unconsolidated affiliates.



	Year Ended December 31,
Revenues by Products and Services:	2009		2010		2011
	(in millions)
Retail gas sales	$	4,540	$	4,412	$	4,019
Wholesale gas sales	902		1,250		1,149
Gas transport	691		785		824
Energy products and services	124		122		110
Total	$	6,257	$	6,569	$	6,102

- Definition

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

+ References

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+ Details