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Document And Entity Information - USD ($) $ in Millions	12 Months Ended
Document And Entity Information - USD ($) $ in Millions	Dec. 31, 2012	Jun. 30, 2012
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	2012
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012

STATEMENTS OF CONSOLIDATED INCOME - USD ($) $ in Millions	12 Months Ended
STATEMENTS OF CONSOLIDATED INCOME - USD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Revenues	$ 4,901	$ 6,102	$ 6,569
Expenses:
Natural gas	2,873	4,055	4,574
Operation and maintenance	951	964	913
Depreciation and amortization	285	262	248
Taxes other than income taxes	146	159	167
Goodwill impairment	252	0	0
Total	4,507	5,440	5,902
Operating Income	394	662	667
Other Income (Expense):
Interest and other finance charges	(179)	(190)	(208)
Equity in earnings of unconsolidated affiliates	31	30	29
Step acquisition gain	136	0	0
Other, net	1	1	(1)
Total	(11)	(159)	(180)
Income Before Income Taxes	383	503	487
Income tax expense	246	187	187
Net Income	$ 137	$ 316	$ 300

Statements of Consolidated Comprehensive Income (Parenthetical) (Parentheticals) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Adjustment to Pension and Other Postretirement Plans, Tax	$ 5	$ 1	$ 1

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Statement of Other Comprehensive Income [Abstract]
Net Income	$ 137	$ 316	$ 300
Other comprehensive income (loss), net of tax:
Adjustment to pension and other postretirement plans (net of tax of $1, $1 and $5)	6	(2)	(1)
Other comprehensive income (loss)	6	(2)	(1)
Comprehensive income	$ 143	$ 314	$ 299

- 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 + Details

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6518256

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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-URI http://asc.fasb.org/extlink&oid=6519514

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-Number 87-21
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-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
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-Paragraph 19
-Article 5

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+ Details

- Definition

Net of tax amount of other comprehensive income (loss) attributable to the parent entity.

+ References

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+ Details

CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Millions

Dec. 31, 2012

Dec. 31, 2011

Current Assets:

Cash and cash equivalents

$ 1

Accounts receivable, net

544

542

Accrued unbilled revenue

258

253

Accounts and notes receivable - affiliated companies

Inventory

228

273

Non-trading derivative assets

Taxes receivable

Deferred income tax assets

Prepaid expenses and other current assets

133

122

Total current assets

1,215

1,304

Property, plant and equipment, net

7,901

7,030

Other Assets:

Goodwill

1,468

1,696

Non-trading derivative assets

Investment in unconsolidated affiliates

405

472

Other

195

165

Total other assets

2,074

2,353

Total Assets

11,190

10,687

Current Liabilities:

Short-term borrowings

^[1]

Current portion of long-term debt

^[1]

365

Accounts payable

443

427

Accounts and notes payable - affiliated companies

818

419

Taxes accrued

Interest accrued

Customer deposits

Non-trading derivative liabilities

Other

177

157

Total current liabilities

2,054

1,315

Other Liabilities:

Accumulated deferred income taxes, net

1,676

1,420

Non-trading derivative liabilities

Benefit obligations

122

108

Regulatory liabilities

619

597

Other

208

232

Total other liabilities

2,627

2,363

Long-term Debt

2,276

2,919

Stockholder's equity

4,233

4,090

Total Liabilities and Stockholder's Equity

$ 11,190

$ 10,687

[1]	Includes amounts due or exchangeable within one year of the date noted.

STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Cash Flows from Operating Activities:
Net Income	$ 137	$ 316	$ 300
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	285	262	248
Amortization of deferred financing costs	13	13	9
Deferred income taxes	245	144	208
Goodwill impairment	252	0	0
Step acquisition gain	(136)	0	0
Write-down of natural gas inventory	4	11	6
Equity in earnings of unconsolidated affiliates, net of distributions	8	8	13
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net.	6	67	120
Accounts receivable/payable, affiliates	5	(14)	6
Inventory	41	20	(52)
Taxes receivable	1	62	(16)
Accounts payable	2	(101)	(35)
Fuel cost recovery	(52)	(70)	(9)
Interest and taxes accrued	(11)	6	5
Non-trading derivatives, net	19	(10)	(5)
Margin deposits, net.	53	34	7
Other current assets	(10)	11	(20)
Other current liabilities	8	(12)	(14)
Other assets	(13)	(3)	(7)
Other liabilities	(28)	22	(21)
Other, net	7	3	(21)
Net cash provided by operating activities	836	769	722
Cash Flows from Investing Activities:
Capital expenditures, net of acquisitions	(566)	(644)	(917)
Acquisitions, net of cash acquired	(360)	0	0
Investment in unconsolidated affiliates	(5)	(12)	(18)
Other, net	8	10	20
Net cash used in investing activities	(923)	(646)	(915)
Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings, net	(24)	9	(2)
Proceeds from (payments of) commercial paper, net	(285)	102	183
Proceeds from long-term debt	0	550	0
Payments of long-term debt	0	(606)	(45)
Cash paid for debt exchange	0	(58)	0
Debt issuance costs	0	(14)	0
Increase (decrease) in notes payable to affiliates	396	(106)	57
Net cash provided by (used in) financing activities	87	(123)	193
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	163	177	191
Income taxes (refunds), net	3	(20)	141
Non-cash transactions:
Accounts payable related to capital expenditures	$ 60	$ 53	$ 98

STATEMENTS OF CONSOLIDATED STOCKHOLDER'S EQUITY - USD ($) $ in Millions	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]
Balance (in shares) at Dec. 31, 2009		1,000
Balance at Dec. 31, 2009		$ 0	$ 2,416	$ 1,065
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)
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)
Net Income	137			137
Balance (in shares) at Dec. 31, 2012		1,000
Balance at Dec. 31, 2012	$ 4,233	$ 0	$ 2,416	$ 1,818	1
Adjustment to pension and postretirement plans					$ (1)

- 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

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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, 2012
Organization, Consolidation and Presentation of Financial Statements [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. 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, 2012

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.

Prior to July 2012, CERC owned 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 2010, CERC invested $20 million in Waskom. On July 31, 2012, CERC purchased the 50% interest that it did not already own in Waskom, as well as other gathering and related assets from a third-party for approximately $273 million. The amount of the purchase price allocated to the acquisition of the 50% interest in Waskom was approximately $201 million, with the remaining purchase price allocated to the other gathering assets, based on a discounted cash flow methodology. The $273 million purchase price was allocated as follows: $253 million to property, plant and equipment; $16 million to goodwill; and the remaining balance to other assets and liabilities. The purchase of the 50% interest in Waskom was determined to be a business combination achieved in stages, and as such CERC recorded a pre-tax gain of approximately $136 million on July 31, 2012, which is the result of remeasuring CERC's original 50% interest in Waskom to fair value. As a result of the purchase, CERC recorded goodwill of $24 million, which includes $17 million related to Waskom (including the re-measurement of its existing 50% interest) and $7 million related to the other gathering and related assets.

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 both December 31, 2011 and 2012, these removal costs of $573 million 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 2010, 2011 and 2012, CERC capitalized interest and AFUDC of $7 million, less than $1 million and $2 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 recorded at the invoiced amount and do not bear interest. It is the policy of management to review the outstanding accounts receivable monthly, as well as the bad debt write-offs experienced in the past, and establish an allowance for doubtful accounts. Account balances are charged off against the allowance when management determines it is probable the receivable will not be recovered. Accounts receivable are net of an allowance for doubtful accounts of $24 million and $23 million at December 31, 2011 and 2012, respectively. The provision for doubtful accounts in CERC’s Statements of Consolidated Income for 2010, 2011 and 2012 was $30 million, $25 million and $15 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 2011 and 2012, CERC recorded $11 million and $4 million, respectively, in write-downs of natural gas inventory to the lower of average cost or market.



	December 31,
	2011		2012
	(in millions)
Materials and supplies	$	86	$	83
Natural gas	187		145
Total inventory	$	273	$	228

(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

Management believes the impact of 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, 2011 and 2012 were $17 million and $12 million, respectively, of margin deposits and $63 million and $86 million, respectively of under-recovered gas cost. Included in other current liabilities on the Consolidated Balance Sheets at December 31, 2011 and 2012 were $14 million and $6 million, respectively, of over-recovered gas cost.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2012

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)	2011		2012
		(in millions)
Natural Gas Distribution	32	$	3,959	$	4,321
Competitive Natural Gas Sales and Services	26	76		80
Interstate Pipelines	56	2,675		2,803
Field Services	42	1,754		2,359
Other property	12	55		52
Total		8,519		9,615
Accumulated depreciation and amortization:
Natural Gas Distribution		1,069		1,194
Competitive Natural Gas Sales and Services		20		25
Interstate Pipelines		302		355
Field Services		72		118
Other property		26		22
Total accumulated depreciation and amortization		1,489		1,714
Property, plant and equipment, net		$	7,030	$	7,901

(b) Depreciation and Amortization

The following table presents depreciation and amortization expense for 2010, 2011 and 2012:



	Year Ended December 31,
	2010		2011		2012
	(in millions)
Depreciation expense	$	232	$	244	$	267
Amortization expense	16		18		18
Total depreciation and amortization expense	$	248	$	262	$	285

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



	December 31,
	2011		2012
Beginning balance	$	58	$	132
Accretion expense	3		6
Revisions in estimates of cash flows	71		(3		)
Ending balance	$	132	$	135

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. The decrease of $3 million in the ARO from the revision of estimate in 2012 is primarily attributable to a steel pipe replacement effort during 2012 which shifted the cost of removal obligation further into the future and lowered the current liability. There were no material additions or settlements during the years ended December 31, 2011 or 2012.

- 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, 2012

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill Disclosure [Text Block]

Goodwill

Goodwill by reportable business segment as of December 31, 2011 and 2012 is as follows (in millions):



	December 31, 2011		Impairment Charge		Acquisition		December 31, 2012
Natural Gas Distribution	$	746	$	—	$	—	$	746
Interstate Pipelines	579		—		—		579
Competitive Natural Gas Sales and Services	335		252		—		83
Field Services	25		—		24		49
Other Operations	11		—		—		11
Total	$	1,696	$	252	$	24	$	1,468

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 its annual impairment test in the third quarter of 2012 and determined that a non-cash goodwill impairment charge in the amount of $252 million was required for the Competitive Natural Gas Sales and Services reportable segment. CERC also determined that no impairment charge was required for any other reportable segment.

CERC estimated the value of the Competitive Natural Gas Sales and Services reporting unit using an income approach. Under this approach, the fair value of the reporting unit is determined by using the present value of future expected cash flows, which cash flows are based on management projections of revenue growth, gross margin, and overall market conditions. These estimated future cash flows are then discounted using a rate that approximates the weighted average cost of capital of a market participant.

The Competitive Natural Gas Sales and Services reporting unit fair value analysis resulted in an implied fair value of goodwill of $83 million for this reporting unit, and as a result, a non-cash impairment charge in the amount of $252 million was recorded in the third quarter of 2012. The adverse wholesale market conditions facing CERC’s energy services business, specifically the prospects for continued low geographic and seasonal price differentials for natural gas, led to a reduction in the estimate of the fair value of goodwill associated with this reporting unit.

Regulatory Matters

12 Months Ended

Dec. 31, 2012

Regulatory Matters [Abstract]

Regulatory Matters

The following is a list of regulatory assets/liabilities reflected on CERC's Consolidated Balance Sheets as of December 31, 2011 and 2012:



	December 31,
	2011			2012
	(in millions)
Regulatory assets in other long-term assets (1)	$	97		$	105
Regulatory liabilities	(597		)	(619		)
Net	$	(500	)	$	(514	)

________________


(1)	Regulatory assets that are not earning a return were not material at December 31, 2011 and 2012.

Employee Benefit Plans

12 Months Ended

Dec. 31, 2012

Compensation and Retirement Disclosure [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 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 $34 million, $30 million and $32 million for the years ended December 31, 2010, 2011 and 2012, 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 $1 million, $2 million and $2 million for the years ended December 31, 2010, 2011 and 2012, 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 $16 million, $17 million and $18 million for the years ended December 31, 2010, 2011, and 2012, 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,
	2010			2011			2012
	(in millions)
Service cost — benefits earned during the period	$	1		$	1		$	1
Interest cost on accumulated benefit obligation	7			6			5
Expected return on plan assets	(1		)	(1		)	(1		)
Amortization of prior service cost	2			2			2
Amortization of net loss	—			1			3
Net postretirement benefit cost	$	9		$	9		$	10

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



	Year Ended December 31,
	2010		2011		2012
Discount rate	5.70	%	5.20	%	4.80	%
Expected return on plan assets	4.50	%	4.50	%	3.10	%

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 2011 and 2012. The measurement dates for plan assets and obligations were December 31, 2011 and 2012.



	December 31,
	2011			2012
	(in millions , except for actuarial assumptions)
Change in Benefit Obligation
Accumulated benefit obligation, beginning of year	$	112		$	118
Service cost	1			1
Interest cost	6			5
Benefits paid	(14		)	(13		)
Participant contributions	4			4
Medicare reimbursement	2			2
Early retiree reinsurance program reimbursement	1			—
Actuarial loss	6			16
Accumulated benefit obligation, end of year	$	118		$	133
Change in Plan Assets
Plan assets, beginning of year	$	22		$	22
Benefits paid	(14		)	(13		)
Employer contributions	9			9
Participant contributions	4			4
Actual investment return	1			2
Plan assets, end of year	$	22		$	24
Amounts Recognized in Balance Sheets
Current liabilities-other	$	(7	)	$	(7	)
Other liabilities-benefit obligations	(89		)	(102		)
Net liability, end of year	$	(96	)	$	(109	)
Actuarial Assumptions
Discount rate	4.80		%	3.90		%
Expected long-term return on assets	3.10		%	3.10		%
Healthcare cost trend rate assumed for the next year	8.00		%	9.00		%
Prescription cost trend rate assumed for the next year	8.00		%	9.00		%
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 9.00% during 2013, after which this rate decreases until reaching the ultimate trend rate of 5.50% in 2017.

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



	December 31,
	2011			2012
	(in millions)
Unrecognized actuarial loss	$	28		$	20
Unrecognized prior service cost	4			2
Total recognized in accumulated other comprehensive loss	32			22
Less deferred tax benefit (1)	(25		)	(21		)
Net amount recognized in accumulated other comprehensive loss	$	7		$	1

________________


(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 2012 are as follows:



	Postretirement Benefits
	(in millions)
Net loss	$	(8	)
Amortization of prior service cost	(2		)
Total recognized in other comprehensive income	$	(10	)

The total expense recognized in net periodic costs and other comprehensive income was $-0- for postretirement benefits for the year ended December 31, 2012.

The amounts in accumulated other comprehensive loss expected to be recognized as components of net periodic benefit cost during 2013 are as follows:



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

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:



U.S. equity	15-25%
International equity	2-12%
Fixed income	68-78%
Cash	0-2%

The fair values of CERC’s postretirement plan assets at December 31, 2011 and 2012, by asset category are as follows:



	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.



	Fair Value Measurements at December 31, 2012 (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)	$	24	$	24	$	—	$	—
Total	$	24	$	24	$	—	$	—

________________


(1)	70% of the amount invested in mutual funds was in fixed income securities; 23% was in U.S. equities and 7% was in international equities.

CERC expects to contribute $8 million to its postretirement benefits plan in 2013. The following benefit payments are expected to be made by the postretirement benefit plan:



	Postretirement Benefit Plan
	Benefit Payments		Medicare Subsidy Receipts
	(in millions)
2013	$	11	$	(2	)
2014	11		(2		)
2015	11		(2		)
2016	12		(2		)
2017	12		(2		)
2018-2022	64		(16		)

(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 $1 million, expense of $4 million and expense of $5 million for the years ended December 31, 2010, 2011 and 2012, respectively. Amounts relating to postemployment benefits included in “Benefit Obligations” in the accompanying Consolidated Balance Sheets at December 31, 2011 and 2012, were $12 million and $14 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 2010, 2011 and 2012, 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, 2011 and 2012 were $3 million and $2 million, respectively.

(f) Other Employee Matters

As of December 31, 2012, approximately 28% of CERC's employees were covered by collective bargaining agreements.

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-URI http://asc.fasb.org/topic&trid=2235017

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Implementation Guide (Q and A)
-Number FAS88
-Paragraph 63
-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 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 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 106
-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 5: 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 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 03-2
-Paragraph 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 87
-Paragraph 264
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph q
-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 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph h
-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 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 8
-Subparagraph m
-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 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5, 6, 7, 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 158
-Paragraph 7, 21, 22
-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 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Staff Position (FSP)
-Number FAS106-2
-Paragraph 20, 21, 22
-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 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 30
-Paragraph 26
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2012
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 $383 million and $779 million at December 31, 2011 and 2012, respectively, which are included in accounts and notes payable —affiliated companies in the Consolidated Balance Sheets. At December 31, 2012, CERC’s money pool borrowings had a weighted-average interest rate of 0.1%. CERC had net interest expense related to affiliate borrowings of $2 million, less than $1 million and $4 million for the years ended December 31, 2010, 2011 and 2012, 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, $164 million and $163 million for 2010, 2011 and 2012, respectively, and are included primarily in operation and maintenance expenses. No dividends were paid to the parent in 2010, 2011 and 2012.

- Definition

The entire disclosure for related party transactions. 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
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-Name Accounting Standards Codification
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-Publisher SEC
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-Number 210
-Section 04
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-Article 3A

Reference 8: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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+ Details

Derivative Instruments

12 Months Ended

Dec. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [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, 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. During the year ended December 31, 2012, CERC recorded decreased natural gas revenues from unrealized net losses of $68 million and decreased natural gas expense from unrealized net gains of $52 million, a net unrealized loss of $16 million.

Weather Hedges. CERC has weather normalization or other rate mechanisms that mitigate the impact of weather on its gas operations in Arkansas, Louisiana, Mississippi, Oklahoma and a portion of Texas. The remaining Gas Operations jurisdictions do not have such mechanisms. As a result, fluctuations from normal weather may have a significant positive or negative effect on the results of the gas operations in the remaining jurisdictions. CERC enters into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its 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, 2010, 2011 and 2012, CERC recognized losses of $-0-, losses of less than $1 million and gains of $8 million, respectively, related to these swaps. The 2011/2012 winter weather hedge had a maximum payment limit of $11 million. Due to the warmer than normal weather, the maximum was reached by February 2012. Weather hedge gains and 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, 2011 and 2012, while the last table provides a breakdown of the related income statement impacts for the years ending December 31, 2011 and 2012.



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 derivatives (1)	Current Assets: Non-trading derivative assets	$	88	$	1
Natural gas derivatives (1)	Other Assets: Non-trading derivative assets	20		—
Natural gas derivatives (1)	Current Liabilities: Non-trading derivative liabilities	15		110
Natural gas derivatives (1)	Other Liabilities: Non-trading derivative 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 billion cubic feet (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.



Fair Value of Derivative Instruments
	December 31, 2012
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 derivatives (1)	Current Assets: Non-trading derivative assets	$	37	$	1
Natural gas derivatives (1)	Other Assets: Non-trading derivative assets	6		—
Natural gas derivatives (1)	Current Liabilities: Non-trading derivative liabilities	5		27
Natural gas derivatives (1)	Other Liabilities: Non-trading derivative liabilities	1		4
Total		$	49	$	32

________________


(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 489 Bcf or a net 101 Bcf long position. Of the net long position, basis swaps constitute 73 Bcf.


(3)	The net of total non-trading derivative assets and liabilities is a $26 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 $9 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	2011			2012
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenue	$	102		$	43
Natural gas derivatives (1)	Gains (Losses) in Expense: Natural Gas	(144		)	(63		)
Total		$	(42	)	$	(20	)

________________


(1)	The Gains (Losses) in Expense: Natural Gas includes $(107) million and $(38) million of costs in 2011 and 2012, 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, 2011 and 2012 was $39 million and $5 million, respectively. The aggregate fair value of assets that are already posted as collateral was less than $1 million at both December 31, 2011 and 2012. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at December 31, 2011 and 2012, $38 million and $5 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, 2011 and 2012 (in millions):



	December 31, 2011				December 31, 2012
	Investment Grade(1)		Total		Investment Grade(1)		Total
Energy marketers	$	1	$	7	$	1	$	1
Financial institutions	—		—		—		—
Retail end users (2)	—		100		—		41
Total	$	1	$	107	$	1	$	42

________________

(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

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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
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Reference 22: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Financial Accounting Standard (FAS)
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+ Details

Fair Value Measurements

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [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. 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. Currently, CERC’s Level 3 assets and liabilities are comprised of physical forward contracts and options. Level 3 physical forward contracts are valued using a discounted cash flow model which includes illiquid forward price curve locations (ranging from $3.07-$4.79 per one million British thermal units (Btu)) as an unobservable input. Level 3 options are valued through Black-Scholes (including forward start) option models which include option volatilities (ranging from 0-58%) as an unobservable input. CERC’s Level 3 derivative assets and liabilities consist of both long and short positions (forwards and options) and their fair value is sensitive to forward prices and volatilities. If forward prices decrease, CERC’s long forwards lose value whereas its short forwards gain in value. If volatility decreases, CERC’s long options lose value whereas its short options gain in value. Instruments classified as Level 3 include the revaluation of the Competitive Natural Gas Sales and Services reporting unit (See Note 4).

CERC determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the year ended December 31, 2012, there were no transfers between Level 1 and 2 with regard to Natural Gas derivatives. CERC also recognizes purchases of Level 3 financial assets and liabilities at their fair market 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, 2011 and 2012, 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, 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.



	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, 2012
	(in millions)
Assets
Corporate equities	$	1	$	—	$	—	$	—		$	1
Investments, including money market funds	11		—		—		—			11
Natural gas derivatives	1		40		7		(6		)	42
Total assets	$	13	$	40	$	7	$	(6	)	$	54
Liabilities
Natural gas derivatives	$	5	$	21	$	5	$	(15	)	$	16
Total liabilities	$	5	$	21	$	5	$	(15	)	$	16

________________


(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 $9 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,
	2010			2011			2012
	(in millions)
Beginning balance	$	(6	)	$	3		$	6
Total gains or (losses):
Included in earnings	4			6			3
Included in regulatory assets	(1		)	—			—
Total settlements:
Included in earnings	(2		)	(3		)	(6		)
Included in regulatory assets	8			—			—
Total purchases	—			2			—
Transfers out of Level 3⁽¹⁾	—			(2		)	(1		)
Ending balance	$	3		$	6		$	2
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	4		$	5		$	1

________


(1)	During 2010, 2011 and 2012, CERC did not have material Level 3 sales or significant transfers into Level 3.

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, 2011				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	2,919	$	3,272	$	2,641	$	3,094

- Definition

The entire disclosure of the fair value measurement of assets and liabilities, which includes financial instruments measured at fair value that are classified in shareholders' equity, which may be measured on a recurring or nonrecurring basis.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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-Topic 820
-SubTopic 10
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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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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.

+ Details

Short-term Borrowings and Long-term Debt

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Short-term Borrowings and Long-term Debt



	December 31, 2011					December 31, 2012
	Long-Term			Current(1)		Long-Term			Current(1)
	(in millions)
Short-term borrowings:
Inventory financing	$	—		$	62	$	—		$	38
Total short-term borrowings	—			62		—			38
Long-term debt:
Senior notes 4.50% to 7.875% due 2013 to 2041	2,693			—		2,328			365
Commercial paper (2)	285			—		—			—
Unamortized discount and premium	(59		)	—		(52		)	—
Total long-term debt	2,919			—		2,276			365
Total debt	$	2,919		$	62	$	2,276		$	403

________________


(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

Inventory Financing. Gas Operations has 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 $62 million and $38 million as of December 31, 2011 and 2012, respectively.


(b)	Long-term Debt

Revolving Credit Facility. As of December 31, 2011 and 2012, CERC had the following revolving credit facility and utilization of such facility (in millions):



December 31, 2011								December 31, 2012
Size of Facility		Loans		Letters of Credit		Commercial Paper		Size of Facility		Loans		Letters of Credit		Commercial Paper
$	950	$	—	$	—	$	285	$	950	$	—	$	—	$	—

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, 2012.

Maturities. CERC’s consolidated maturities of long-term debt are $365 million in 2013, $160 million in 2014, $-0- in 2015, $325 million in 2016 and $250 million in 2017.

- 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, 2012

Income Taxes [Abstract]

Income Taxes

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



	Year Ended December 31,
	2010			2011		2012
	(in millions)
Current income tax expense (benefit):
Federal	$	(38	)	$	34	$	—
State	17			9		1
Total current expense (benefit)	(21		)	43		1
Deferred income tax expense (benefit):
Federal	234			140		198
State	(26		)	4		47
Total deferred expense	208			144		245
Total income tax expense	$	187		$	187	$	246

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,
	2010			2011			2012
	(in millions)
Income before income taxes	$	487		$	503		$	383
Federal statutory income tax rate	35		%	35		%	35		%
Expected federal income tax expense	170			176			134
Increase (decrease) in tax expense resulting from:
State income tax expense (benefit), net of federal income tax	(6		)	9			31
Increase (decrease) in settled and uncertain income tax positions	5			1			(7		)
Tax law change in deductibility of retiree health care costs	18			—			—
Goodwill impairment	—			—			88
Other, net	—			1			—
Total	17			11			112
Total income tax expense	$	187		$	187		$	246
Effective tax rate	38.4		%	37.2		%	64.2		%

CERC recorded an effective tax rate of 64.2% for 2012 compared to 37.2% for 2011. The increase in the effective tax rate is primarily due to the goodwill impairment of $252 million which is non-deductible for tax in 2012 and higher state tax expense compared to 2011 related to benefits recognized in that prior period for lower blended state rates. The increased rate was partially offset by the release of income tax reserves of $7 million.

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



	December 31,
	2011			2012
	(in millions)
Deferred tax assets:
Current:
Allowance for doubtful accounts	$	9		$	9
Other	(1		)	—
Total current deferred tax assets	8			9
Non-current:
Employee benefits	57			49
Loss and credit carryforwards	238			192
Regulatory liabilities, net	—			196
Other	60			51
Total non-current deferred tax assets before valuation allowance	355			488
Valuation allowance	(3		)	(2		)
Total non-current deferred tax assets, net of valuation allowance	352			486
Total deferred tax assets, net of valuation allowance	360			495
Deferred tax liabilities:
Current:
Deferred gas costs	—			25
Other	—			5
Total current deferred tax liabilities	—			30
Non-current:
Depreciation	1,696			2,033
Regulatory assets, net	17			—
Other	59			129
Total non-current deferred tax liabilities	1,772			2,162
Total deferred tax liabilities	1,772			2,192
Accumulated deferred income taxes, net	$	1,412		$	1,697

Tax Attribute Carryforwards and Valuation Allowance. At December 31, 2012, CERC has approximately $487 million of federal net operating loss carryforwards which begin to expire in 2031 and approximately $377 million of state net operating loss carryforwards which expire in various years between 2013 and 2032. CERC has approximately $1 million of federal capital loss carryforwards and $1 million of federal charitable contribution carryforwards which expire in various years between 2013 and 2032.

CERC has approximately $244 million of state capital loss carryforwards which expire in 2017 for which management established a full valuation allowance of $3 million state tax effect ($2 million net of federal income tax). The valuation allowance was established based upon management's evaluation that it may not be realized.

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



	December 31,
	2010			2011			2012
	(in millions)
Balance, beginning of year	$	6		$	11		$	8
Tax Positions related to prior years:
Additions	—			(1		)	—
Reductions	(2		)	(3		)	(27		)
Tax Positions related to current year:
Additions	7			1			—
Settlements	—			—			(1		)
Balance, end of year	$	11		$	8		$	(20	)

The net decrease in the total amount of unrecognized tax benefits during 2012 is primarily related to the re-measurement of certain unrecognized tax benefits related to an Internal Revenue Service (IRS) issuance of new guidance with respect to repairs on tangible property and CERC's IRS settlements for tax years 2006 through 2009. CERC does not expect the change to the amount of unrecognized tax benefits over the twelve months ending December 31, 2013 to materially impact the financial position of CERC.

CERC had approximately $5 million, $6 million and $-0- of unrecognized tax benefits that, if recognized, would affect the effective income tax rate for 2010, 2011and 2012, respectively. CERC recognizes interest and penalties as a component of income tax expense. CERC recognized approximately $0.4 million of income tax expense, $0.4 million of income tax expense and $3 million of income tax benefit related to interest on uncertain income tax positions during 2010, 2011 and 2012, respectively. CERC had approximately $4 million and $7 million of interest receivable on uncertain income tax positions accrued at December 31, 2011 and 2012, respectively.

Tax Audits and Settlements. CenterPoint Energy's consolidated federal income tax returns have been audited and settled through the 2009 tax year. CenterPoint Energy has filed claims for income tax refunds that are pending review by the IRS for tax years 2002, 2003 and 2004. CenterPoint Energy is currently under examination by the IRS for tax years 2010 and 2011 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, 2012.

- 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 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 2: 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

Reference 3: 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 4: 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 5: 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 6: 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 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 8: 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.

+ Details

Commitments and Contingencies

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [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, 2011 and 2012 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, 2012, minimum payment obligations for natural gas supply commitments are approximately $430 million in 2013, $344 million in 2014, $214 million in 2015, $149 million in 2016, $96 million in 2017 and $156 million after 2017.

(b) Asset Management Agreements

Gas Operations has 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, 2012, which primarily consist of rental agreements for building space, data processing equipment, compression equipment and rights of way (in millions):



2013	$	12
2014	8
2015	5
2016	5
2017	3
2018 and beyond	13
Total	$	46

Total lease expense for all operating leases was $76 million, $42 million and $26 million in 2010, 2011 and 2012, respectively.

(d) Long-Term Gas Gathering and Treating Agreements

CenterPoint Energy Field Services, LLC (CEFS) has 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 have been 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 RRI changed its name to RRI Energy, Inc. In December 2010, Mirant Corporation merged with and became a wholly owned subsidiary of RRI, and RRI changed its name to GenOn Energy, Inc. (GenOn). In December 2012, NRG acquired GenOn through a merger in which GenOn became a wholly owned subsidiary of NRG. None of the sale of the retail business, the merger with Mirant Corporation, or the acquisition of GenOn by NRG 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 were 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 since 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. In September 2012, the Nevada Supreme Court affirmed the dismissal. In October 2012, the Nevada Supreme Court granted the plaintiffs’ motion to stay the dismissal of this case pending the filing and final disposition of their petition for a writ of certiorari to the Supreme Court of the United States. In December 2012, the plaintiffs filed a petition for writ of certiorari with the Supreme Court of the United States. On January 4, 2013, the Supreme Court removed the case from its docket since the plaintiffs’ petition exceeded the applicable word limit. In February 2013, the plaintiffs filed a corrected petition with the 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 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. In July 2012, the plaintiffs filed a motion to dismiss certain defendants from both lawsuits, including the remaining CERC Corp. defendants.

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.

As of December 31, 2012, CERC had recorded a liability of $14 million for remediation of these Minnesota sites. The estimated range of possible remediation costs for the sites CERC believes it has responsibility for 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 Utilities Commission includes approximately $285,000 annually in rates to fund normal on-going remediation costs. As of December 31, 2012, CERC had collected $5.8 million from insurance companies to be used for future environmental remediation.

In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CERC 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, based on its experience to date, does not expect 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 remediated 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 $73 million as of December 31, 2012. Based on market conditions in the fourth quarter of 2012 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. As a result, CERC returned to GenOn in the fourth quarter of 2012 the approximately $28 million of aggregate collateral previously posted by GenOn under the agreement. If GenOn should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, any collateral then provided as security may be insufficient to satisfy CERC's obligations.

- Definition

The entire disclosure for commitments and contingencies.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6449706&loc=d3e16207-108621

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 460
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6398077&loc=d3e12565-110249

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 450
-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14435-108349

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.25)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 440
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6394976&loc=d3e25287-109308

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 14
-Paragraph 3
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 9, 10, 11, 12
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Unaudited Quarterly Information

12 Months Ended

Dec. 31, 2012

Unaudited Quarterly Information [Abstract]

Quarterly Financial Information [Text Block]

Unaudited Quarterly Information

Summarized quarterly financial data is as follows:



	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



	Year Ended December 31, 2012
	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
	(in millions)
Revenues	$	1,550	$	846	$	954		$	1,551
Operating income (loss)	229		106		(152		)	211
Net income (loss)	118		42		(127		)	104

- 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, 2012

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, 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
As of and for the year ended December 31, 2012:
Natural Gas Distribution	$	2,320	$	22		$	173	$	226		$	4,775		$	359
Competitive Natural Gas Sales and Services	1,758		26			6		(250		)	839			6
Interstate Pipelines (1)	356		146			56		207			4,004			132
Field Services (2)	467		39			50		214			2,453			52
Other	—		—			—		(3		)	647			—
Reconciling Eliminations	—		(233		)	—		—			(1,528		)	—
Consolidated	$	4,901	$	—		$	285	$	394		$	11,190		$	549

________________

(1)

Interstate Pipelines recorded equity income of $19 million, $21 million and $26 million in the years ended December 31, 2010, 2011 and 2012, 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 $413 million, $409 million and $404 million as of December 31, 2010, 2011 and 2012, respectively, and is included in Investment in unconsolidated affiliates.

(2)

Field Services recorded equity income of $10 million, $9 million and $5 million for the years ended December 31, 2010, 2011 and 2012, 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 $55 million and $63 million as of December 31, 2010 and 2011, respectively, and is included in Investment in unconsolidated affiliates. Beginning on August 1, 2012, financial results for Waskom are included in operating income due to the July 31, 2012 purchase of the 50% interest in Waskom that CERC did not already own.



	Year Ended December 31,
Revenues by Products and Services:	2010		2011		2012
	(in millions)
Retail gas sales	$	4,412	$	4,019	$	3,328
Wholesale gas sales	1,250		1,149		613
Gas transportation and processing	785		824		847
Energy products and services	122		110		113
Total	$	6,569	$	6,102	$	4,901

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8981-108599

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e9038-108599

Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Publisher FASB
-Name Accounting Standards Codification
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8906-108599

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 131
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2012
Significant Accounting Policies [Abstract]
Use Of Estimates	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.
Principles of Consolidation	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. Prior to July 2012, CERC owned 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 2010, CERC invested $20 million in Waskom. On July 31, 2012, CERC purchased the 50% interest that it did not already own in Waskom, as well as other gathering and related assets from a third-party for approximately $273 million. The amount of the purchase price allocated to the acquisition of the 50% interest in Waskom was approximately $201 million, with the remaining purchase price allocated to the other gathering assets, based on a discounted cash flow methodology. The $273 million purchase price was allocated as follows: $253 million to property, plant and equipment; $16 million to goodwill; and the remaining balance to other assets and liabilities. The purchase of the 50% interest in Waskom was determined to be a business combination achieved in stages, and as such CERC recorded a pre-tax gain of approximately $136 million on July 31, 2012, which is the result of remeasuring CERC's original 50% interest in Waskom to fair value. As a result of the purchase, CERC recorded goodwill of $24 million, which includes $17 million related to Waskom (including the re-measurement of its existing 50% interest) and $7 million related to the other gathering and related assets. Other investments, excluding marketable securities, are carried at cost.
Revenues	Revenues 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.
Long-lived Assets and Intangibles	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.
Regulatory Assets and Liabilities	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 both December 31, 2011 and 2012, these removal costs of $573 million 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.
Depreciation and Amortization Expense	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.
Capitalization of Interest and Allowance for Funds Used During Construction	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 2010, 2011 and 2012, CERC capitalized interest and AFUDC of $7 million, less than $1 million and $2 million, respectively.
Income Taxes	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.
Accounts Receivable and Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable are recorded at the invoiced amount and do not bear interest. It is the policy of management to review the outstanding accounts receivable monthly, as well as the bad debt write-offs experienced in the past, and establish an allowance for doubtful accounts. Account balances are charged off against the allowance when management determines it is probable the receivable will not be recovered. Accounts receivable are net of an allowance for doubtful accounts of $24 million and $23 million at December 31, 2011 and 2012, respectively. The provision for doubtful accounts in CERC’s Statements of Consolidated Income for 2010, 2011 and 2012 was $30 million, $25 million and $15 million, respectively.
Inventory	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 2011 and 2012, CERC recorded $11 million and $4 million, respectively, in write-downs of natural gas inventory to the lower of average cost or market.
Derivative Instruments	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.
Environmental Costs	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.
Statement of Consolidated Cash Flows	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.
New Accounting Pronouncements	New Accounting Pronouncements Management believes the impact of 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.
Other Current Assets and Liabilities	Other Current Assets and Liabilities Included in other current assets on the Consolidated Balance Sheets at December 31, 2011 and 2012 were $17 million and $12 million, respectively, of margin deposits and $63 million and $86 million, respectively of under-recovered gas cost. Included in other current liabilities on the Consolidated Balance Sheets at December 31, 2011 and 2012 were $14 million and $6 million, respectively, of over-recovered gas cost.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Significant Accounting Policies [Abstract]

Schedule of Inventory [Table Text Block]



	December 31,
	2011		2012
	(in millions)
Materials and supplies	$	86	$	83
Natural gas	187		145
Total inventory	$	273	$	228

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, plant and equipment includes the following:



	Weighted Average Useful Lives	December 31,
	(Years)	2011		2012
		(in millions)
Natural Gas Distribution	32	$	3,959	$	4,321
Competitive Natural Gas Sales and Services	26	76		80
Interstate Pipelines	56	2,675		2,803
Field Services	42	1,754		2,359
Other property	12	55		52
Total		8,519		9,615
Accumulated depreciation and amortization:
Natural Gas Distribution		1,069		1,194
Competitive Natural Gas Sales and Services		20		25
Interstate Pipelines		302		355
Field Services		72		118
Other property		26		22
Total accumulated depreciation and amortization		1,489		1,714
Property, plant and equipment, net		$	7,030	$	7,901

Depreciation And Amortization [Table Text Block]

The following table presents depreciation and amortization expense for 2010, 2011 and 2012:



	Year Ended December 31,
	2010		2011		2012
	(in millions)
Depreciation expense	$	232	$	244	$	267
Amortization expense	16		18		18
Total depreciation and amortization expense	$	248	$	262	$	285

Asset Retirement Obligations

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



	December 31,
	2011		2012
Beginning balance	$	58	$	132
Accretion expense	3		6
Revisions in estimates of cash flows	71		(3		)
Ending balance	$	132	$	135

Goodwill (Tables)

12 Months Ended

Dec. 31, 2012

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

Goodwill by reportable business segment as of December 31, 2011 and 2012 is as follows (in millions):



	December 31, 2011		Impairment Charge		Acquisition		December 31, 2012
Natural Gas Distribution	$	746	$	—	$	—	$	746
Interstate Pipelines	579		—		—		579
Competitive Natural Gas Sales and Services	335		252		—		83
Field Services	25		—		24		49
Other Operations	11		—		—		11
Total	$	1,696	$	252	$	24	$	1,468

- Definition

Tabular disclosure of goodwill by reportable segment and in total which includes a rollforward schedule.

+ References + Details

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2012

Regulatory Matters [Abstract]

Schedule of Regulatory Assets and Liabilities

The following is a list of regulatory assets/liabilities reflected on CERC's Consolidated Balance Sheets as of December 31, 2011 and 2012:



	December 31,
	2011			2012
	(in millions)
Regulatory assets in other long-term assets (1)	$	97		$	105
Regulatory liabilities	(597		)	(619		)
Net	$	(500	)	$	(514	)

________________


(1)	Regulatory assets that are not earning a return were not material at December 31, 2011 and 2012.

Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2012

Compensation and Retirement Disclosure [Abstract]

Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year [Table Text Block]

The amounts in accumulated other comprehensive loss expected to be recognized as components of net periodic benefit cost during 2013 are as follows:



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

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

The following benefit payments are expected to be made by the postretirement benefit plan:



	Postretirement Benefit Plan
	Benefit Payments		Medicare Subsidy Receipts
	(in millions)
2013	$	11	$	(2	)
2014	11		(2		)
2015	11		(2		)
2016	12		(2		)
2017	12		(2		)
2018-2022	64		(16		)



	December 31,
	2011			2012
	(in millions , except for actuarial assumptions)
Change in Benefit Obligation
Accumulated benefit obligation, beginning of year	$	112		$	118
Service cost	1			1
Interest cost	6			5
Benefits paid	(14		)	(13		)
Participant contributions	4			4
Medicare reimbursement	2			2
Early retiree reinsurance program reimbursement	1			—
Actuarial loss	6			16
Accumulated benefit obligation, end of year	$	118		$	133
Change in Plan Assets
Plan assets, beginning of year	$	22		$	22
Benefits paid	(14		)	(13		)
Employer contributions	9			9
Participant contributions	4			4
Actual investment return	1			2
Plan assets, end of year	$	22		$	24
Amounts Recognized in Balance Sheets
Current liabilities-other	$	(7	)	$	(7	)
Other liabilities-benefit obligations	(89		)	(102		)
Net liability, end of year	$	(96	)	$	(109	)
Actuarial Assumptions
Discount rate	4.80		%	3.90		%
Expected long-term return on assets	3.10		%	3.10		%
Healthcare cost trend rate assumed for the next year	8.00		%	9.00		%
Prescription cost trend rate assumed for the next year	8.00		%	9.00		%
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

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



U.S. equity	15-25%
International equity	2-12%
Fixed income	68-78%
Cash	0-2%

The net postretirement benefit cost includes the following components:



	Year Ended December 31,
	2010			2011			2012
	(in millions)
Service cost — benefits earned during the period	$	1		$	1		$	1
Interest cost on accumulated benefit obligation	7			6			5
Expected return on plan assets	(1		)	(1		)	(1		)
Amortization of prior service cost	2			2			2
Amortization of net loss	—			1			3
Net postretirement benefit cost	$	9		$	9		$	10

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



	Year Ended December 31,
	2010		2011		2012
Discount rate	5.70	%	5.20	%	4.80	%
Expected return on plan assets	4.50	%	4.50	%	3.10	%

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



	December 31,
	2011			2012
	(in millions)
Unrecognized actuarial loss	$	28		$	20
Unrecognized prior service cost	4			2
Total recognized in accumulated other comprehensive loss	32			22
Less deferred tax benefit (1)	(25		)	(21		)
Net amount recognized in accumulated other comprehensive loss	$	7		$	1

________________


(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 2012 are as follows:



	Postretirement Benefits
	(in millions)
Net loss	$	(8	)
Amortization of prior service cost	(2		)
Total recognized in other comprehensive income	$	(10	)

Defined Benefit Plan Schedule Of Effect Of One Percentage Point Change In Assumed Health Care Cost Trend Rates Text Block



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

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Text Block]

The fair values of CERC’s postretirement plan assets at December 31, 2011 and 2012, by asset category are as follows:



	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.



	Fair Value Measurements at December 31, 2012 (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)	$	24	$	24	$	—	$	—
Total	$	24	$	24	$	—	$	—

________________


(1)	70% of the amount invested in mutual funds was in fixed income securities; 23% was in U.S. equities and 7% was in international equities.

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=21915506&loc=d3e2439-114920

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Topic 715
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-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 55
-Paragraph 17
-URI http://asc.fasb.org/extlink&oid=21916443&loc=d3e4179-114921

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 158
-Paragraph 4, 7, 16, 20, 21
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5, 6, 7
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value



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 derivatives (1)	Current Assets: Non-trading derivative assets	$	88	$	1
Natural gas derivatives (1)	Other Assets: Non-trading derivative assets	20		—
Natural gas derivatives (1)	Current Liabilities: Non-trading derivative liabilities	15		110
Natural gas derivatives (1)	Other Liabilities: Non-trading derivative 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 billion cubic feet (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.



Fair Value of Derivative Instruments
	December 31, 2012
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 derivatives (1)	Current Assets: Non-trading derivative assets	$	37	$	1
Natural gas derivatives (1)	Other Assets: Non-trading derivative assets	6		—
Natural gas derivatives (1)	Current Liabilities: Non-trading derivative liabilities	5		27
Natural gas derivatives (1)	Other Liabilities: Non-trading derivative liabilities	1		4
Total		$	49	$	32

________________


(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 489 Bcf or a net 101 Bcf long position. Of the net long position, basis swaps constitute 73 Bcf.


(3)	The net of total non-trading derivative assets and liabilities is a $26 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 $9 million.

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance



Income Statement Impact of Derivative Activity
		Year Ended December 31,
Total derivatives not designated as hedging instruments	Income Statement Location	2011			2012
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenue	$	102		$	43
Natural gas derivatives (1)	Gains (Losses) in Expense: Natural Gas	(144		)	(63		)
Total		$	(42	)	$	(20	)

________________


(1)	The Gains (Losses) in Expense: Natural Gas includes $(107) million and $(38) million of costs in 2011 and 2012, respectively, associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered through purchased gas adjustments.

Credit Quality Of Counterparties



	December 31, 2011				December 31, 2012
	Investment Grade(1)		Total		Investment Grade(1)		Total
Energy marketers	$	1	$	7	$	1	$	1
Financial institutions	—		—		—		—
Retail end users (2)	—		100		—		41
Total	$	1	$	107	$	1	$	42

________________

(1)


(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

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

+ References + Details

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

Fair Value, Assets Measured on Recurring Basis [Table Text Block]



	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.



	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, 2012
	(in millions)
Assets
Corporate equities	$	1	$	—	$	—	$	—		$	1
Investments, including money market funds	11		—		—		—			11
Natural gas derivatives	1		40		7		(6		)	42
Total assets	$	13	$	40	$	7	$	(6	)	$	54
Liabilities
Natural gas derivatives	$	5	$	21	$	5	$	(15	)	$	16
Total liabilities	$	5	$	21	$	5	$	(15	)	$	16

________________


(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 $9 million posted with the same counterparties.

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]



	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	Year Ended December 31,
	2010			2011			2012
	(in millions)
Beginning balance	$	(6	)	$	3		$	6
Total gains or (losses):
Included in earnings	4			6			3
Included in regulatory assets	(1		)	—			—
Total settlements:
Included in earnings	(2		)	(3		)	(6		)
Included in regulatory assets	8			—			—
Total purchases	—			2			—
Transfers out of Level 3⁽¹⁾	—			(2		)	(1		)
Ending balance	$	3		$	6		$	2
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	4		$	5		$	1

Fair Value, by Balance Sheet Grouping [Table Text Block]



	December 31, 2011				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	2,919	$	3,272	$	2,641	$	3,094

- Definition

Tabular disclosure of assets, including [financial] instruments measured at fair value that are classified in stockholders' equity, if any, by class that are measured at fair value on a recurring basis. The disclosures contemplated herein include the fair value measurements at the reporting date by the level within the fair value hierarchy in which the fair value measurements in their entirety fall, segregating fair value measurements using quoted prices in active markets for identical assets (Level 1), significant other observable inputs (Level 2), and significant unobservable inputs (Level 3).

+ References + Details

- Definition

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

+ References + Details

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13476-108611

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 820
-SubTopic 10
-Section 50
-Paragraph 2
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=7578670&loc=d3e19207-110258

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13467-108611

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6447952&loc=d3e13220-108610

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 30
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14172-108612

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 10
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13433-108611

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 19
-Subparagraph a, b, c(1), d(1)
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 14
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15
-Subparagraph b-d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 18
-Subparagraph c(2), d, e, f
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32
-Subparagraph a, c(1), c(2), c(3), d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 12: 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.

+ Details

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

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Schedule of Debt [Table Text Block]



	December 31, 2011					December 31, 2012
	Long-Term			Current(1)		Long-Term			Current(1)
	(in millions)
Short-term borrowings:
Inventory financing	$	—		$	62	$	—		$	38
Total short-term borrowings	—			62		—			38
Long-term debt:
Senior notes 4.50% to 7.875% due 2013 to 2041	2,693			—		2,328			365
Commercial paper (2)	285			—		—			—
Unamortized discount and premium	(59		)	—		(52		)	—
Total long-term debt	2,919			—		2,276			365
Total debt	$	2,919		$	62	$	2,276		$	403

________________


(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.

Schedule of Line of Credit Facilities [Table Text Block]

Revolving Credit Facility. As of December 31, 2011 and 2012, CERC had the following revolving credit facility and utilization of such facility (in millions):



December 31, 2011								December 31, 2012
Size of Facility		Loans		Letters of Credit		Commercial Paper		Size of Facility		Loans		Letters of Credit		Commercial Paper
$	950	$	—	$	—	$	285	$	950	$	—	$	—	$	—

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Taxes [Abstract]

Income Tax Expense Disclosure

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



	Year Ended December 31,
	2010			2011		2012
	(in millions)
Current income tax expense (benefit):
Federal	$	(38	)	$	34	$	—
State	17			9		1
Total current expense (benefit)	(21		)	43		1
Deferred income tax expense (benefit):
Federal	234			140		198
State	(26		)	4		47
Total deferred expense	208			144		245
Total income tax expense	$	187		$	187	$	246

Reconciliation Of Expected Federal Income Tax Expense To Actual

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,
	2010			2011			2012
	(in millions)
Income before income taxes	$	487		$	503		$	383
Federal statutory income tax rate	35		%	35		%	35		%
Expected federal income tax expense	170			176			134
Increase (decrease) in tax expense resulting from:
State income tax expense (benefit), net of federal income tax	(6		)	9			31
Increase (decrease) in settled and uncertain income tax positions	5			1			(7		)
Tax law change in deductibility of retiree health care costs	18			—			—
Goodwill impairment	—			—			88
Other, net	—			1			—
Total	17			11			112
Total income tax expense	$	187		$	187		$	246
Effective tax rate	38.4		%	37.2		%	64.2		%

Income Tax Asset Liability Disclosure

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



	December 31,
	2011			2012
	(in millions)
Deferred tax assets:
Current:
Allowance for doubtful accounts	$	9		$	9
Other	(1		)	—
Total current deferred tax assets	8			9
Non-current:
Employee benefits	57			49
Loss and credit carryforwards	238			192
Regulatory liabilities, net	—			196
Other	60			51
Total non-current deferred tax assets before valuation allowance	355			488
Valuation allowance	(3		)	(2		)
Total non-current deferred tax assets, net of valuation allowance	352			486
Total deferred tax assets, net of valuation allowance	360			495
Deferred tax liabilities:
Current:
Deferred gas costs	—			25
Other	—			5
Total current deferred tax liabilities	—			30
Non-current:
Depreciation	1,696			2,033
Regulatory assets, net	17			—
Other	59			129
Total non-current deferred tax liabilities	1,772			2,162
Total deferred tax liabilities	1,772			2,192
Accumulated deferred income taxes, net	$	1,412		$	1,697

Uncertain Income Tax Positions

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



	December 31,
	2010			2011			2012
	(in millions)
Balance, beginning of year	$	6		$	11		$	8
Tax Positions related to prior years:
Additions	—			(1		)	—
Reductions	(2		)	(3		)	(27		)
Tax Positions related to current year:
Additions	7			1			—
Settlements	—			—			(1		)
Balance, end of year	$	11		$	8		$	(20	)

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Operating Leases of Lessee Disclosure [Table Text Block]



2013	$	12
2014	8
2015	5
2016	5
2017	3
2018 and beyond	13
Total	$	46

- Definition

Tabular disclosure of a lessee's leasing arrangements including: (1) the basis on which contingent rental payments are determined, (2) the existence and terms of renewal or purchase options and escalation clauses, (3) restrictions imposed by lease arrangements, such as those concerning dividends, additional debt, and further leasing, (4) rent holidays, rent concessions, or leasehold improvement incentives and unusual provisions or conditions. Disclosure may also include the specific period used to amortize material leasehold improvements made at the inception of the lease or during the lease term. Additionally, for operating leases having initial or remaining noncancelable lease terms in excess of one year: (a) future minimum rental payments required as of the date of the latest balance sheet presented, in the aggregate and for each of the five succeeding fiscal years, (b) the total of minimum rentals to be received in the future under noncancelable subleases as of the date of the latest balance sheet presented, and (c) for all operating leases, rental expense for each period for which an income statement is presented, with separate amounts for minimum rentals, contingent rentals, and sublease rentals. Rental payments under leases with terms of a month or less that were not renewed need not be included.

+ References + Details

Unaudited Quarterly Information (Tables)

12 Months Ended

Dec. 31, 2012

Unaudited Quarterly Information [Abstract]

Quarterly financial data

Summarized quarterly financial data is as follows:



	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



	Year Ended December 31, 2012
	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
	(in millions)
Revenues	$	1,550	$	846	$	954		$	1,551
Operating income (loss)	229		106		(152		)	211
Net income (loss)	118		42		(127		)	104

Reportable Business Segments (Tables)

12 Months Ended

Dec. 31, 2012

Reportable Business Segments [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

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, 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
As of and for the year ended December 31, 2012:
Natural Gas Distribution	$	2,320	$	22		$	173	$	226		$	4,775		$	359
Competitive Natural Gas Sales and Services	1,758		26			6		(250		)	839			6
Interstate Pipelines (1)	356		146			56		207			4,004			132
Field Services (2)	467		39			50		214			2,453			52
Other	—		—			—		(3		)	647			—
Reconciling Eliminations	—		(233		)	—		—			(1,528		)	—
Consolidated	$	4,901	$	—		$	285	$	394		$	11,190		$	549

________________

(1)

(2)

Revenue from External Customers by Products and Services [Table Text Block]



	Year Ended December 31,
Revenues by Products and Services:	2010		2011		2012
	(in millions)
Retail gas sales	$	4,412	$	4,019	$	3,328
Wholesale gas sales	1,250		1,149		613
Gas transportation and processing	785		824		847
Energy products and services	122		110		113
Total	$	6,569	$	6,102	$	4,901

- Definition

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

+ References + Details

Schedule II Valuation and Qualifying Accounts (Tables)

12 Months Ended

Dec. 31, 2012

Valuation and Qualifying Accounts Disclosure [Line Items]

Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

(An Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

For the Three Years Ended December 31, 2012



Column A	Column B		Column C					Column D		Column E
Description	Balance at Beginning of Period		Additions					Deductions From Reserves (1)		Balance at End of Period
Description	Balance at Beginning of Period		Charged to Income			Charged to Other Accounts		Deductions From Reserves (1)		Balance at End of Period
	(in millions)
Year Ended December 31, 2012:
Accumulated provisions:
Uncollectible accounts receivable	$	24	$	15		$	—	$	16	$	23
Deferred tax asset valuation allowance	3		(1		)	—		—		2
Year Ended December 31, 2011:
Accumulated provisions:
Uncollectible accounts receivable	$	25	$	25		$	—	$	26	$	24
Deferred tax asset valuation allowance	3		—			—		—		3
Year Ended December 31, 2010:
Accumulated provisions:
Uncollectible accounts receivable	$	23	$	30		$	—	$	28	$	25
Deferred tax asset valuation allowance	5		(2		)	—		—		3

________________


(1)	Deductions from reserves represent losses or expenses for which the respective reserves were created. In the case of the uncollectible accounts reserve, such deductions are net of recoveries of amounts previously written off.

Summary of Significant Accounting Policies (Details) $ in Millions	1 Months Ended	12 Months Ended
	Jul. 31, 2012 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Jun. 30, 2012
Summary of Accounting Policies [Line Items]
Minimum Ownership Interest Percentage For Investments Recorded Using Entity Method		20.00%
Maximum Ownership Interest Percentage For Investments Recorded Using Entity Method		50.00%
Length of Southeast Supply Header's interstate natural gas pipeline (in miles)		274
Business Acquisition, Purchase Price Allocation, Remaining Interest	$ 201
Business Acquisition, Cost of Acquired Entity, Cash Paid	273
Business Acquisition, Purchase Price Allocation, Property, Plant and Equipment	253
Business Acquisition, Purchase Price Allocation, Goodwill Amount	16
Step acquisition gain	136	$ 136	$ 0	$ 0
Acquisition	$ 24	24
Allowance for doubtful accounts		23	24
Provision for doubtful accounts		15	25	30
Amount of removal costs recognized as a component of depreciation expense recorded as a regulatory liability		573	573
Amount of capitalized interest and allowance for funds used during construction		(2)	(1)	(7)
Write-downs of natural gas inventory to lower of cost or market		4	11
Materials and supplies		83	86
Natural gas		145	187
Total inventory		228	273
Margin deposits		12	17
Under Recovered Gas Costs		86	63
Over Recovered Gas Costs		$ 6	$ 14
Southeast Supply Header Llc [Member]
Summary of Accounting Policies [Line Items]
Percentage of ownership interest		50.00%
Waskom Gas Processing Company [Member]
Summary of Accounting Policies [Line Items]
Percentage of ownership interest					50.00%
Investment during the period in Waskom				$ 20
Percentage of Ownership in Affiliate 2 Acquired	50.00%
Waskom [Member]
Summary of Accounting Policies [Line Items]
Acquisition	$ 17
Gathering and Related Assets [Member]
Summary of Accounting Policies [Line Items]
Acquisition	$ 7

Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 9,615	$ 8,519
Accumulated depreciation and amortization	1,714	1,489
Property, Plant and Equipment, Net	7,901	7,030
Depreciation expense	267	244	$ 232
Amortization expense	18	18	16
Total depreciation and amortization expense	285	262	248
Beginning balance	132	58
Accretion expense	6	3
Revisions in estimates of cash flows	(3)	71
Ending balance	135	132	$ 58
Increase (Decrease) in ARO from the revision of estimate	$ (3)	71
Natural Gas Distribution [Member]
Property, Plant and Equipment [Line Items]
Weighted Average Useful Lives (in years)	32
Property, Plant and Equipment, Gross	$ 4,321	3,959
Accumulated depreciation and amortization	$ 1,194	1,069
Competitive Natural Gas Sales and Services [Member]
Property, Plant and Equipment [Line Items]
Weighted Average Useful Lives (in years)	26
Property, Plant and Equipment, Gross	$ 80	76
Accumulated depreciation and amortization	$ 25	20
Interstate Pipelines [Member]
Property, Plant and Equipment [Line Items]
Weighted Average Useful Lives (in years)	56
Property, Plant and Equipment, Gross	$ 2,803	2,675
Accumulated depreciation and amortization	$ 355	302
Field Services [Member]
Property, Plant and Equipment [Line Items]
Weighted Average Useful Lives (in years)	42
Property, Plant and Equipment, Gross	$ 2,359	1,754
Accumulated depreciation and amortization	$ 118	72
Other property [Member]
Property, Plant and Equipment [Line Items]
Weighted Average Useful Lives (in years)	12
Property, Plant and Equipment, Gross	$ 52	55
Accumulated depreciation and amortization	$ 22	$ 26

Goodwill (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
Goodwill (Details) - USD ($) $ in Millions	Jul. 31, 2012	Sep. 30, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Goodwill [Line Items]
Goodwill			$ 1,468	$ 1,696
Impairment Charge		$ 252	252	0	$ 0
Acquisition	$ 24		24
Natural Gas Distribution [Member]
Goodwill [Line Items]
Goodwill			746	746
Impairment Charge			0
Acquisition			0
Interstate Pipelines [Member]
Goodwill [Line Items]
Goodwill			579	579
Impairment Charge			0
Acquisition			0
Competitive Natural Gas Sales and Services [Member]
Goodwill [Line Items]
Goodwill			83	335
Impairment Charge			252
Acquisition			0
Field Services [Member]
Goodwill [Line Items]
Goodwill			49	25
Impairment Charge			0
Acquisition			24
Other Operations [Member]
Goodwill [Line Items]
Goodwill			11	$ 11
Impairment Charge			0
Acquisition			$ 0

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=14024403&loc=d3e13816-109267

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6388280&loc=d3e13770-109266

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 43
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 72
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-Clause 1
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 68
-Subparagraph l
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 34
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

- Definition

Loss recognized during the period that results from the write-down of goodwill after comparing the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. Goodwill is assessed at least annually for impairment.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 2
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=14024403&loc=d3e13854-109267

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6388280&loc=d3e13777-109266

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6943989&loc=d3e3602-108585

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (e)
-URI http://asc.fasb.org/extlink&oid=14024403&loc=d3e13816-109267

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 72
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 43
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 20
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-Clause 5
-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 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 47
-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.

+ Details

Regulatory Matters (Details) - USD ($)
$ in Millions

Dec. 31, 2012

Dec. 31, 2011

Mar. 31, 2010

Schedule of Regulatory Assets and Liabilities [Line Items]

Regulatory assets in other long-term assets

$ 1

Regulatory liabilities

$ (619)

$ (597)

Net Regulatory Assets (Liabilities)

(514)

(500)

Other Longterm Regulatory Assets Member

Schedule of Regulatory Assets and Liabilities [Line Items]

Regulatory assets in other long-term assets

^[1]

$ 105

$ 97

[1]	Regulatory assets that are not earning a return were not material at December 31, 2011 and 2012.

Employee Benefit Plans Pension and Postretirement Benefits (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Pension and Savings Plan

New percentage of eligible earnings used to determine retirement benefits (in hundredths)

5.00%

Pension Expense

$ 32

$ 30

$ 34

Non Qualified Pension Plan Benefit Expense

Non Qualified Pension Plan Expense

$ 1

Maximum Percentage Of Employee Compensation Eligible For Contribution To Savings Plan

50.00%

Description Of Company Match Under Savings Plan

100% of the first 6% of each employee’s compensation contributed

Savings Plan Benefit Expense

$ 18

Components of net periodic benefit cost

Service cost - benefits earned during the period

Interest cost on accumulated benefit obligation

Expected return on plan assets

(1)

Amortization of prior service cost

Amortization of net loss

Net postretirement benefit cost

$ 10

$ 9

Assumptions used to determine net postretirement benefit costs

Discount rate

4.80%

5.20%

5.70%

Expected return on plan assets

3.10%

4.50%

Change in Plan Assets [Roll Forward]

Plan assets, beginning of year

$ 22

Plan assets, end of year

$ 22

Amounts Recognized in Balance Sheets

Other liabilities - benefit obligations

$ (122)

(108)

Actuarial Assumptions

Healthcare cost trend rate assumed for the next year

9.00%

Rate to which the cost trend rate is assumed to decline (ultimate trend rate)

5.50%

Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate Support, Methodology and Source Data

one-half to 99 years.

Amounts recognized in accumulated other comprehensive loss

Unrecognized actuarial loss

$ 20

Unrecognized prior service cost

Total recognized in accumulated other comprehensive loss

Less deferred tax benefit

^[1]

(21)

(25)

Net amount recognized in accumulated other comprehensive loss

Changes in plan assets and benefit obligations recognized in other comprehensive income

Net loss

(8)

Amortization of prior service cost

(2)

Total recognized in other comprehensive income

(10)

Total expense recognized in net periodic cost and other comprehensive income

Amounts that will be amortized from accumulated other comprehensive loss in next fiscal year

Unrecognized actuarial loss

Unrecognized prior service cost

Amounts in accumulated other comprehensive loss to be recognized as net periodic cost

Effect of a one-percentage point change in assumed healthcare cost trend rates

Effect of One Percentage Point Increase on Postretirement Benefit Obligation

Effect of One Percentage Point Increase on Total of Service and Interest Cost

Effect of One Percentage Point Decrease on Postretirement Benefit Obligation

(3)

Effect of One Percentage Point Decrease on Total of Service and Interest Cost

Other Postretirement Benefit Plans, Defined Benefit [Member]

Change in Benefit Obligation [Roll Forward]

Accumulated benefit obligation, beginning of year

118

112

Service cost

Interest cost

Benefits paid

(13)

(14)

Participant contributions

Medicare reimbursement

Early retiree reinsurance program reimbursement

Actuarial Loss

Accumulated benefit obligation, end of year

133

118

$ 112

Change in Plan Assets [Roll Forward]

Plan assets, beginning of year

Benefits paid

(13)

(14)

Employer contributions

Participant contributions

Actual investment return

Plan assets, end of year

$ 22

Amounts Recognized in Balance Sheets

Current liabilities - other

(7)

Other liabilities - benefit obligations

(102)

(89)

Net liability, end of year

$ (109)

$ (96)

Actuarial Assumptions

Discount rate

3.90%

4.80%

Expected long-term return on assets

3.10%

Healthcare cost trend rate assumed for the next year

9.00%

8.00%

Prescription cost trend rate assumed for the next year

9.00%

8.00%

Rate to which the cost trend rate is assumed to decline (ultimate trend rate)

5.50%

Year that the healthcare rate reaches the ultimate trend rate

2017

Year that the prescription drug rate reaches the ultimate trend rate

2017

[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.

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

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Fair Value of Plan Assets

$ 24

$ 22

Percentage of investment in mutual funds allocated to fixed income securities

70.00%

72.00%

Percentage of investment in mutual funds allocated to U.S. equities

23.00%

22.00%

Percentage of investment in mutual funds allocated to international equities

7.00%

6.00%

Estimated contributions next fiscal year

$ 8

Postemployment Benefits

Postemployment benefit income (expense)

(5)

$ (4)

$ 1

Postemployment benefits included in Benefit Obligations

Benefit expense related to deferred compensation plans

Other non-qualified plans benefit obligations deferred compensation

Equity Funds [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Fair Value of Plan Assets

^[1]

^[2]

Fair Value, Inputs, Level 1 [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Fair Value of Plan Assets

Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Fair Value of Plan Assets

^[1]

^[2]

Fair Value, Inputs, Level 2 [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Fair Value of Plan Assets

Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Fair Value of Plan Assets

^[1]

^[2]

Fair Value, Inputs, Level 3 [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Fair Value of Plan Assets

Fair Value, Inputs, Level 3 [Member] | Equity Funds [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Fair Value of Plan Assets

^[1]

^[2]

Other Postretirement Benefit Plans, Defined Benefit [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Fair Value of Plan Assets

$ 22

Expected Future Benefit Payments, Fiscal Year Maturity

Benefit Payments - 2013

Benefit Payments - 2014

Benefit Payments - 2015

Benefit Payments - 2016

Benefit Payments - 2017

Benefit Payments - 2018-2022

Medicare Subsidy Receipts - 2013

(2)

Medicare Subsidy Receipts - 2014

(2)

Medicare Subsidy Receipts - 2015

(2)

Medicare Subsidy Receipts - 2016

(2)

Medicare Subsidy Receipts - 2017

(2)

Medicare Subsidy Receipts - 2018-2022

$ (16)

Other Postretirement Benefit Plans, Defined Benefit [Member] | U.S. Equity [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Defined Benefit Plan, Target Plan Asset Allocations Range Minimum

15.00%

Defined Benefit Plan, Target Plan Asset Allocations Range Maximum

25.00%

Other Postretirement Benefit Plans, Defined Benefit [Member] | International Equity [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Defined Benefit Plan, Target Plan Asset Allocations Range Minimum

2.00%

Defined Benefit Plan, Target Plan Asset Allocations Range Maximum

12.00%

Other Postretirement Benefit Plans, Defined Benefit [Member] | Fixed Income [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Defined Benefit Plan, Target Plan Asset Allocations Range Minimum

68.00%

Defined Benefit Plan, Target Plan Asset Allocations Range Maximum

78.00%

Other Postretirement Benefit Plans, Defined Benefit [Member] | Cash and Cash Equivalents [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Defined Benefit Plan, Target Plan Asset Allocations Range Minimum

0.00%

Defined Benefit Plan, Target Plan Asset Allocations Range Maximum

2.00%

[1]	70% of the amount invested in mutual funds was in fixed income securities; 23% was in U.S. equities and 7% was in international equities.
[2]	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.

Employee Benefit Plans Other Employee Matters (Details)	12 Months Ended
Employee Benefit Plans Other Employee Matters (Details)	Dec. 31, 2012
Workforce Subject to Collective Bargaining Arrangements [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	28.00%

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Related Party Transaction [Line Items]
Money Pool Borrowings	$ 779	$ 383
Money Pool Borrowings Weighted-Average Interest Rate	0.10%
Net interest expense related to affiliate borrowings	$ 4	1	$ 2
Corporate services charge	163	164	154
Dividends paid to parent	$ 0	$ 0	$ 0

Derivative Instruments (Details)
MMcf in Thousands, $ in Millions

12 Months Ended

Dec. 31, 2012

USD ($)

MMcf

Dec. 31, 2011

USD ($)

MMcf

Dec. 31, 2010

USD ($)

Derivative Assets Investment Grade Non Trading

^[1]

$ 1

Derivative Assets Non Trading

107

Increased (Decreased) Natural Gas Revenues From Unrealized Net Gains (Losses)

(68)

$ 18

Increased (Decreased) Natural Gas Expense From Unrealized Net Losses (Gains)

(52)

Net Unrealized Gain (Loss)

(16)

Weather Hedges Gain Loss Recognized

$ 8

$ (1)

$ 0

Derivative gross volumes on natural gas contracts (in MMcf) | MMcf

489

633

Net long position (in MMcf) | MMcf

101

Amount of net long position constituted by basis swaps (in MMcf) | MMcf

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

Total non-trading derivative assets and liabilities net of collateral

$ 26

$ 55

Collateral Netting

Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net

(20)

(42)

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

Aggregate fair value of assets already posted as collateral

Credit risk contingent feature assets

Weather Hedge Maximum Payment Limit

Gains (Losses) in Revenue [Member] | Natural gas derivatives [Member]

Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net

102

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

Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net

^[2]

(63)

(144)

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

(38)

(107)

Energy Marketers [Member]

Derivative Assets Investment Grade Non Trading

^[1]

Derivative Assets Non Trading

Financial Institutions [Member]

Derivative Assets Investment Grade Non Trading

^[1]

Derivative Assets Non Trading

Retail End Users [Member]

Derivative Assets Investment Grade Non Trading

^[1],[3]

Derivative Assets Non Trading

^[3]

100

Not Designated as Hedging Instrument [Member]

Derivative Assets Fair Value

^[4],[5]

123

^[6],[7]

Derivative Liabilities Fair Value

^[4],[5]

124

^[6],[7]

Not Designated as Hedging Instrument [Member] | Current Assets [Member] | Natural gas derivatives [Member]

Derivative Assets Fair Value

^[8]

^[4],[5]

^[6],[7]

Derivative Liabilities Fair Value

^[8]

^[4],[5]

^[6],[7]

Not Designated as Hedging Instrument [Member] | Other Assets [Member] | Natural gas derivatives [Member]

Derivative Assets Fair Value

^[8]

^[4],[5]

^[6],[7]

Derivative Liabilities Fair Value

^[8]

^[4],[5]

^[6],[7]

Not Designated as Hedging Instrument [Member] | Current Liabilities [Member] | Natural gas derivatives [Member]

Derivative Assets Fair Value

^[8]

^[4],[5]

^[6],[7]

Derivative Liabilities Fair Value

^[8]

^[4],[5]

110

^[6],[7]

Not Designated as Hedging Instrument [Member] | Other Liabilities [Member] | Natural gas derivatives [Member]

Derivative Assets Fair Value

^[8]

^[4],[5]

^[6],[7]

Derivative Liabilities Fair Value

^[8]

$ 4

^[4],[5]

$ 13

^[6],[7]

[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]	The Gains (Losses) in Expense: Natural Gas includes $(107) million and $(38) million of costs in 2011 and 2012, respectively, associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered through purchased gas adjustments.
[3]	Retail end users represent customers who have contracted to fix the price of a portion of their physical gas requirements for future periods.
[4]	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 489 Bcf or a net 101 Bcf long position. Of the net long position, basis swaps constitute 73 Bcf.
[5]	The net of total non-trading derivative assets and liabilities is a $26 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 $9 million.
[6]	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 633 billion cubic feet (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.
[7]	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.
[8]	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.

Fair Value Measurements (Details) - USD ($)

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Assets

Corporate equities

$ 1,000,000

Investments, including money market funds

11,000,000

Natural gas derivatives, assets

42,000,000

107,000,000

Total assets

54,000,000

119,000,000

Liabilities

Natural gas derivatives, liabilities

16,000,000

52,000,000

Total liabilities

16,000,000

52,000,000

Cash collateral posted with counterparties

9,000,000

56,000,000

Carrying Amount [Member]

Liabilities

Long-term debt

2,641,000,000

2,919,000,000

Fair Value [Member]

Liabilities

Long-term debt

3,094,000,000

3,272,000,000

Derivative Financial Instruments Assets And Liabilities Net Member

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation Calculation Roll Forward

Beginning balance

6,000,000

3,000,000

$ (6,000,000)

Total Gains Or Losses:

Included in earnings

3,000,000

6,000,000

4,000,000

Included in regulatory assets

(1,000,000)

Total settlements:

Included in earnings

(6,000,000)

(3,000,000)

(2,000,000)

Included in regulatory assets

8,000,000

Total purchases

2,000,000

Transfers out of Level 3

^[1]

(1,000,000)

(2,000,000)

Ending balance

2,000,000

6,000,000

3,000,000

Amount Of Total Gains For Period Included In Earnings

1,000,000

5,000,000

$ 4,000,000

Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]

Assets

Corporate equities

1,000,000

Investments, including money market funds

11,000,000

Natural gas derivatives, assets

1,000,000

Total assets

13,000,000

Liabilities

Natural gas derivatives, liabilities

5,000,000

19,000,000

Total liabilities

5,000,000

19,000,000

Significant Other Observable Inputs (Level 2) [Member]

Assets

Corporate equities

Investments, including money market funds

Natural gas derivatives, assets

40,000,000

112,000,000

Total assets

40,000,000

112,000,000

Liabilities

Natural gas derivatives, liabilities

21,000,000

101,000,000

Total liabilities

21,000,000

101,000,000

Significant Unobservable Inputs (Level 3) [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Illiquid forward price low range

3.07

Illiquid forward price high range

$ 4.79

Option volatilities low range

0.00%

Option volatilities high range

58.00%

Assets

Corporate equities

$ 0

Investments, including money market funds

Natural gas derivatives, assets

7,000,000

10,000,000

Total assets

7,000,000

10,000,000

Liabilities

Natural gas derivatives, liabilities

5,000,000

4,000,000

Total liabilities

5,000,000

4,000,000

Netting Adjustments [Member]

Assets

Corporate equities

^[2]

^[3]

Investments, including money market funds

^[2]

^[3]

Natural gas derivatives, assets

(6,000,000)

^[2]

(16,000,000)

^[3]

Total assets

(6,000,000)

^[2]

(16,000,000)

^[3]

Liabilities

Natural gas derivatives, liabilities

(15,000,000)

^[2]

(72,000,000)

^[3]

Total liabilities

$ (15,000,000)

^[2]

$ (72,000,000)

^[3]

[1]	During 2010, 2011 and 2012, CERC did not have material Level 3 sales or significant transfers into Level 3.
[2]	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 $9 million posted with the same counterparties.
[3]	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.

Short-term Borrowings and Long-term Debt (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Debt Instrument [Line Items]

Short-term Debt

^[1]

$ 38

$ 62

Long-term Debt

Long-term Debt, Excluding Current Maturities

2,276

2,919

Long-term Debt, Current Maturities

^[1]

365

Short Term Borrowings And Current Portion Long Term Debt

^[1]

403

Long-term Debt, Maturities in 2013

365

Long-term Debt, Maturities in 2014

160

Long-term Debt, Maturities in 2015

Long-term Debt, Maturities in 2016

325

Long-term Debt, Maturities in 2017

250

Inventory financing [Member]

Debt Instrument [Line Items]

Short-term Debt

^[1]

Long-term Debt

Line of Credit [Member] | CERC Corp [Member]

Debt Instrument [Line Items]

950

$ 0

285

Line of Credit Facility, Interest Rate Description

London Interbank Offered Rate plus 150 basis points

Percentage on limitation of debt to total capitalization under covenant (in hundredths)

65.00%

Senior notes 2013 to 2041 [Member]

Debt Instrument [Line Items]

Long-term Debt, Excluding Current Maturities

$ 2,328

2,693

Long-term Debt, Current Maturities

^[1]

$ 365

Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum

4.50%

Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum

7.875%

Commercial Paper [Member]

Debt Instrument [Line Items]

Long-term Debt, Excluding Current Maturities

^[2]

$ 0

285

Long-term Debt, Current Maturities

^[1],[2]

Unamortized Discount Premium Member

Debt Instrument [Line Items]

Long-term Debt, Excluding Current Maturities

(52)

(59)

Long-term Debt, Current Maturities

^[1]

$ 0

[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.

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
Income Taxes (Details) - USD ($) $ in Millions	Sep. 30, 2012	Mar. 31, 2010	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Current income tax expense (benefit):
Federal			$ 0	$ 34	$ (38)
State			1	9	17
Total current expense (benefit)			1	43	(21)
Deferred income tax expense (benefit):
Federal			198	140	234
State			47	4	(26)
Total deferred expense			245	144	208
Total income tax expense			246	187	187
Income tax reconciliation
Income before income taxes			$ 383	$ 503	$ 487
Federal statutory income tax rate			35.00%	35.00%	35.00%
Expected federal income tax expense			$ 134	$ 176	$ 170
Increase (decrease) in tax expense resulting from:
State income tax expense (benefit), net of federal income tax			31	9	(6)
Increase (decrease) in settled and uncertain income tax positions			(7)	1	5
Tax law change in deductibility of retiree health care costs			0	0	18
Goodwill impairment			88	0	0
Other, net			0	1	0
Total			112	11	17
Total income tax expense			$ 246	$ 187	$ 187
Effective tax rate			64.20%	37.20%	38.40%
Goodwill impairment	$ 252		$ 252	$ 0	$ 0
Tax Adjustments, Settlements, and Unusual Provisions			(7)
Amount of reduction to deferred tax assets due to actuarially determined net present value of lost future health care deductions		$ 22
Amount of non-cash recorded to income tax expense as result of change in tax law					19
Amount of reduction to deferred tax assets, recorded to income tax expense, due to actuarially determined net present value of lost future health care deductions		19
Regulatory Assets		1
Amount of decrease in income tax expense recorded related to effects of re-measuring accumulated deferred income taxes					24
Amount of net reduction to income tax expense from state income tax expense, net of federal income tax				20	29
Increase in income tax expense related to uncertain tax positions					5
Deferred Tax Assets [Abstract]
Allowance for Doubtful Accounts			9	9
Other, current deferred tax assets			0	(1)
Total current deferred tax assets			9	8
Employee Benefits			49	57
Loss And Credit Carryforwards			192	238
Regulatory liabilities, net		2	196	0
Other, noncurrent deferred tax assets			51	60
Total non-current deferred tax assets before valuation allowance			488	355
Valuation Allowance			(2)	(3)
Total non-current deferred tax assets, net of valuation allowance			486	352
Total deferred tax assets, net of valuation allowance			495	360
Deferred Tax Liabilities [Abstract]
Deferred Gas Costs			25	0
Other, current deferred tax liabilities			5	0
Total current deferred tax liabilities			30	0
Depreciation			2,033	1,696
Regulatory assets, net			0	17
Other, non-current deferred tax liabilities			129	59
Total non-current deferred tax liabilities			2,162	1,772
Total deferred tax liabilities			2,192	1,772
Accumulated deferred income taxes, net			1,697	1,412
Reconciliation of Unrecognized Tax Benefits (Expenses) [Roll Forward]
Balance, beginning of year		$ 6	8	11	6
Tax Positions Related to Prior Years:
Additions			0	(1)	0
Reductions			(27)	(3)	(2)
Tax Positions Related to Current Year:
Additions			0	1	7
Reductions			(1)	0	0
Balance, end of year			(20)	8	11
Interest expense on uncertain income tax positions			(3)	0	0
Accrued interest receivable on uncertain income tax positions			7	4
Unrecognized Tax Benefits that Would Impact Effective Tax Rate			0	$ 6	$ 5
Federal [Member]
Deferred Tax Liabilities [Abstract]
Federal net operating loss carryforwards to expire in 2030			$ 487
Operating Loss Carryforwards, Expiration Dates			2031
Other Tax Carryforward, Expiration Dates			2013 and 2032
State [Member]
Deferred Tax Liabilities [Abstract]
Operating Loss Carryforwards, Expiration Dates			2013 and 2032
State net operating loss carryforwards to expire in various years between 2012 and 2031			$ 377
Other Tax Carryforward, Expiration Dates			2017
State capital loss carryforwards which expire in 2017			$ 244
State capital loss carryforwards, full valuation allowance			3
State capital loss carryforwards, valuation allowance net of federal tax			2
Capital Loss Carryforward [Member] \| Federal [Member]
Deferred Tax Liabilities [Abstract]
Other Tax Carryforward, Gross Amount			1
Charitable Contribution Carryforward [Member] \| Federal [Member]
Deferred Tax Liabilities [Abstract]
Other Tax Carryforward, Gross Amount			$ 1

Commitments and Contingencies (Details)	12 Months Ended
Commitments and Contingencies (Details)	Dec. 31, 2012 USD ($) MMcf Years	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Recovery of compensatory damages sought by plaintiffs	in excess of $1 billion
Approximate number of gas market manipulation lawsuits naming CenterPoint Energy and/or Reliant Energy (in number of lawsuits)	30
Number of gas market manipulation lawsuits pending for CenterPoint Energy and its affiliates (in number of lawsuits)	2
Number of gas mismeasurement lawsuits pending for CenterPoint Energy and its affiliates (in number of lawsuits)	2
Approximate number of pipeline companies named in the mismeasurement lawsuits (in number of companies)	245
Number of gas measurement lawsuits seeking class certification and has four amendments (in number of cases)	1
Number of times gas measurement lawsuit was amended (in number of amendments)	4
Number of years the plaintiffs claim the defendants have engaged in the systematic mismeasurement of natural gas (in years) \| Years	25
Number of CenterPoint subsidiaries dismissed from the claims of the plaintiff (in number of claims)	2
Number of sites where remediation is complete, other than ongoing operations (in number of sites)	2
Number of remaining sites in the Minnesota service territory (in number of sites)	5
Number of remaining sites in the Minnesota territory where the company believes it has no liability (in number of sites)	2
Amount accrued for remediation of Minnesota sites	$ 14,000,000
Minimum estimated remediation costs for the Minnesota sites	6,000,000
Maximum estimated remediation costs for the Minnesota sites	$ 41,000,000
Minimum years of remediation for the Minnesota sites (in years) \| Years	30
Maximum years of remediation for the Minnesota sites (in years) \| Years	50
Annual amount included in rates to fund normal on-going remediation costs	$ 285,000
Amount collected from insurance companies to be used for future environmental remediation	5,800,000
Approximate amount of undiscounted maximum potential demand charges under the transportation contracts	73,000,000
Approximate amount of collateral returned	28,000,000
Operating Leases, Future Minimum Payments Due [Abstract]
2013	12,000,000
2014	8,000,000
2015	5,000,000
2016	5,000,000
2017	3,000,000
2018 and beyond	13,000,000
Total	46,000,000
Total lease expense for all operating leases	26,000,000	$ 42,000,000	$ 76,000,000
Natural Gas supply commitments [Member]
Recorded Unconditional Purchase Obligation [Line Items]
2013	430,000,000
2014	344,000,000
2015	214,000,000
2016	149,000,000
2017	96,000,000
After 2017	$ 156,000,000
Long-Term Gas Gathering and Treating Agreements [Member]
Schedule of Capital Expansion Projects [Abstract]
Total Capacity Of System After Potential Additional Expansion (MMcf) \| MMcf	1,300
Estimated Total Capital Expenditures For Expansion	$ 440,000,000

Unaudited Quarterly Information (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Revenues	$ 1,551	$ 954	$ 846	$ 1,550	$ 1,608	$ 1,171	$ 1,228	$ 2,095	$ 4,901	$ 6,102	$ 6,569
Operating Income (Loss)	211	(152)	106	229	177	111	114	260	394	662	667
Net Income (Loss)	$ 104	$ (127)	$ 42	$ 118	$ 93	$ 43	$ 47	$ 133	$ 137	$ 316	$ 300

- Definition

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

+ References

+ Details

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

3 Months Ended

12 Months Ended

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Segment Reporting Information [Line Items]

Revenue from External Customers

$ 4,901

$ 6,102

$ 6,569

Inter-segment Revenues

Depreciation and Amortization

285

262

248

Operating Income (Loss)

$ 211

$ (152)

$ 106

$ 229

$ 177

$ 111

$ 114

$ 260

394

662

667

Total Assets

11,190

10,687

11,190

10,687

10,538

Expenditures for Long-Lived Assets

549

599

974

Equity income

Retail gas sales

3,328

4,019

4,412

Wholesale gas sales

613

1,149

1,250

Gas transportation and processing

847

824

785

Energy products and services

113

110

122

Total

1,551

$ 954

$ 846

$ 1,550

1,608

$ 1,171

$ 1,228

$ 2,095

4,901

6,102

6,569

Natural Gas Distribution [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

2,320

2,823

3,199

Inter-segment Revenues

Depreciation and Amortization

173

166

Operating Income (Loss)

226

231

Total Assets

4,775

4,636

4,775

4,636

4,575

Expenditures for Long-Lived Assets

359

295

202

Competitive Natural Gas Sales and Services [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

1,758

2,488

2,617

Inter-segment Revenues

Depreciation and Amortization

Operating Income (Loss)

(250)

Total Assets

839

1,089

839

1,089

1,190

Expenditures for Long-Lived Assets

Interstate Pipelines [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

^[1]

356

421

464

Inter-segment Revenues

^[1]

146

132

137

Depreciation and Amortization

^[1]

Operating Income (Loss)

^[1]

207

248

270

Total Assets

^[1]

$ 4,004

3,867

4,004

3,867

3,672

Expenditures for Long-Lived Assets

^[1]

132

102

Equity income

$ 26

Interest in jointly-owned asset (in hundredths)

50.00%

Investment in unconsolidated affiliate

$ 404

409

$ 404

409

413

Field Services [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

^[2]

467

370

289

Inter-segment Revenues

^[2]

Depreciation and Amortization

^[2]

Operating Income (Loss)

^[2]

214

189

151

Total Assets

^[2]

$ 2,453

1,894

2,453

1,894

1,803

Expenditures for Long-Lived Assets

^[2]

201

668

Equity income

$ 5

Interest in jointly-owned asset (in hundredths)

50.00%

Investment in unconsolidated affiliate

Other [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

$ 0

Inter-segment Revenues

Depreciation and Amortization

Operating Income (Loss)

(3)

(7)

(1)

Total Assets

$ 647

660

647

660

659

Expenditures for Long-Lived Assets

Reconciling Eliminations [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

Inter-segment Revenues

(233)

(215)

(234)

Depreciation and Amortization

Operating Income (Loss)

Total Assets

$ (1,528)

$ (1,459)

(1,528)

(1,459)

(1,361)

Expenditures for Long-Lived Assets

$ 0

[1]

[2]

Schedule II Valuation and Qualifying Accounts (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Allowance for Trade Receivables [Member]

Valuation and Qualifying Accounts Disclosure [Line Items]

Balance at Beginning of Period

$ 24

$ 25

$ 23

Additions Charged To Income

Additions Charged to Other Accounts

Deductions From Reserves

^[1]

Balance at End of Period

Valuation Allowance of Deferred Tax Assets [Member]

Valuation and Qualifying Accounts Disclosure [Line Items]

Balance at Beginning of Period

Additions Charged To Income

(1)

(2)

Additions Charged to Other Accounts

^[1]

Deductions From Reserves

^[1]

Balance at End of Period

$ 2

$ 3

[1]	Deductions from reserves represent losses or expenses for which the respective reserves were created. In the case of the uncollectible accounts reserve, such deductions are net of recoveries of amounts previously written off.