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Document and Entity Information Document - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Jun. 30, 2013
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 Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding	1,000
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float		$ 0

STATEMENTS OF CONSOLIDATED INCOME - USD ($) $ in Millions	12 Months Ended
STATEMENTS OF CONSOLIDATED INCOME - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues	$ 5,522	$ 4,901	$ 6,102
Expenses:
Natural gas	3,908	2,873	4,055
Operation and maintenance	828	951	964
Depreciation and amortization	230	285	262
Taxes other than income taxes	155	146	159
Goodwill impairment	0	252	0
Total	5,121	4,507	5,440
Operating Income	401	394	662
Other Income (Expense):
Interest and other finance charges	(154)	(179)	(190)
Equity in earnings of unconsolidated affiliates	188	31	30
Step acquisition gain	0	136	0
Other, net	0	1	1
Total	34	(11)	(159)
Income Before Income Taxes	435	383	503
Income tax expense	371	246	187
Net Income	$ 64	$ 137	$ 316

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Comprehensive Income [Abstract]
Net income	$ 64	$ 137	$ 316
Other comprehensive income (loss), net of tax:
Adjustment to postretirement and other postemployment plans (net of tax of $6, $5 and $1)	6	6	(2)
Other comprehensive income (loss)	6	6	(2)
Comprehensive income	$ 70	$ 143	$ 314

- Definition

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

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STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (PARENTHETICAL) (Parentheticals) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	$ (6)	$ (5)	$ 1

CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Millions

Dec. 31, 2013

Dec. 31, 2012

Current Assets:

Cash and cash equivalents

$ 1

Accounts receivable, net

565

544

Accrued unbilled revenue

311

258

Accounts and notes receivable — affiliated companies

Inventory

179

228

Non-trading derivative assets

Taxes receivable

Deferred income tax assets

Prepaid expenses and other current assets

133

Total current assets

1,214

1,215

Property, Plant and Equipment, Net

3,436

7,901

Other Assets:

Goodwill

840

1,468

Non-trading derivative assets

Notes receivable — affiliated companies

363

Investment in unconsolidated affiliates

4,518

405

Other

161

195

Total other assets

5,892

2,074

Total Assets

10,542

11,190

Current Liabilities:

Short-term borrowings

^[1]

Current portion of long-term debt

^[1]

365

Accounts payable

495

443

Accounts and notes payable — affiliated companies

103

818

Taxes accrued

Interest accrued

Customer deposits

Non-trading derivative liabilities

Other

163

177

Total current liabilities

1,009

2,054

Other Liabilities:

Accumulated deferred income taxes, net

2,082

1,676

Non-trading derivative liabilities

Benefit obligations

102

122

Regulatory liabilities

642

619

Other

160

208

Total other liabilities

2,990

2,627

Long-Term Debt

2,240

2,276

Commitments and Contingencies (Note 13)

Stockholder’s Equity

4,303

4,233

Total Liabilities And Stockholder’s Equity

$ 10,542

$ 11,190

[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, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash Flows from Operating Activities:
Net income	$ 64	$ 137	$ 316
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	230	285	262
Amortization of deferred financing costs	11	13	13
Deferred income taxes	357	245	144
Goodwill impairment	0	252	0
Step acquisition gain	0	(136)	0
Write-down of natural gas inventory	4	4	11
Equity in earnings of unconsolidated affiliates, net of distributions	(58)	8	8
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net	(220)	6	67
Accounts receivable/payable, affiliates	(2)	5	(14)
Inventory	(10)	41	20
Taxes receivable	(18)	1	62
Accounts payable	110	2	(101)
Fuel cost recovery	108	(52)	(70)
Interest and taxes accrued	33	(11)	6
Non-trading derivatives, net	4	19	(10)
Margin deposits, net	16	53	34
Other current assets	3	(10)	11
Other current liabilities	5	8	(12)
Other assets	(18)	(13)	(3)
Other liabilities	6	(28)	22
Other, net	10	7	3
Net cash provided by operating activities	635	836	769
Cash Flows from Investing Activities:
Capital expenditures, net of acquisitions	(495)	(566)	(644)
Acquisitions, net of cash acquired	0	(360)	0
Investment in unconsolidated affiliates	0	(5)	(12)
Cash contribution to Enable	(38)	0	0
Other, net	(3)	8	10
Net cash used in investing activities	(536)	(923)	(646)
Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings, net	5	(24)	9
Proceeds from (payments of) commercial paper, net	118	(285)	102
Proceeds from long-term debt	1,050	0	550
Payments of long-term debt	(525)	0	(606)
Cash paid for debt exchange	(5)	0	(58)
Debt issuance costs	(1)	0	(14)
Increase (decrease) in notes payable to affiliates	(741)	396	(106)
Net cash provided by (used in) financing activities	(99)	87	(123)
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	148	163	177
Income taxes (refunds), net	(5)	3	(20)
Non-cash transactions:
Accounts payable related to capital expenditures	21	60	53
Formation of Enable	$ 4,252	$ 0	$ 0

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, 2010		1,000
Balance at Dec. 31, 2010		$ 0	$ 2,416	$ 1,365
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)
Net income	64			64
Balance (in shares) at Dec. 31, 2013		1,000
Balance at Dec. 31, 2013	$ 4,303	$ 0	$ 2,416	$ 1,882	5
Adjustment to pension and postretirement plans					$ 5

- 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, 2013
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), which owns and operates natural gas distribution systems in six states (Gas Operations). A wholly owned subsidiary of CERC Corp. offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities in 21 states. As of December 31, 2013, CERC Corp. also owned approximately 58.3% of the limited partner interests in Enable, an unconsolidated partnership jointly controlled with OGE Energy Corp., which owns, operates and develops natural gas and crude oil infrastructure assets. 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 15.

- Definition

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

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+ Details

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

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 also uses the equity method for investments in which it has ownership percentages greater than 50%, when it exercises significant influence, does not have control and is not considered the primary beneficiary, if applicable.

On March 14, 2013, CenterPoint Energy entered into a Master Formation Agreement (MFA) with OGE Energy Corp. (OGE) and affiliates of ArcLight Capital Partners, LLC (ArcLight), pursuant to which CenterPoint Energy, OGE and ArcLight agreed to form Enable as a private limited partnership. On May 1, 2013, the parties closed on the formation of Enable. In connection with the closing (i) CERC Corp. converted its direct wholly owned subsidiary, CenterPoint Energy Field Services, LLC, a Delaware limited liability company (CEFS), into a Delaware limited partnership that became Enable, (ii) CERC Corp. contributed to Enable its equity interests in each of CenterPoint Energy Gas Transmission Company, LLC, which has been subsequently renamed Enable Gas Transmission, LLC (EGT), CenterPoint Energy - Mississippi River Transmission, LLC, which has been subsequently renamed Enable Mississippi River Transmission, LLC (MRT), certain of its other midstream subsidiaries (Other CNP Midstream Subsidiaries), and a 24.95% interest in Southeast Supply Header, LLC (SESH and, collectively with CEFS, EGT, MRT and Other CNP Midstream Subsidiaries, CenterPoint Midstream), and (iii) OGE and ArcLight indirectly contributed 100% of the equity interests in Enogex LLC, which has been subsequently renamed Enable Oklahoma Intrastate Transmission, LLC (Enogex), to Enable.

As of December 31, 2013, CERC Corp., OGE and ArcLight held approximately 58.3%, 28.5% and 13.2%, respectively, of the limited partner interests in Enable. Enable is equally controlled by CERC Corp. and OGE; each own 50% of the management rights in the general partner of Enable. CERC Corp. and OGE also own a 40% and 60% interest, respectively, in the incentive distribution rights held by the general partner of Enable. The general partner of Enable is currently governed by a board of directors made up of an equal number of representatives designated by each of CERC Corp. and OGE. The investment in Enable is accounted for utilizing the equity method of accounting. As of December 31, 2013, CERC determined that Enable was a variable interest entity (VIE); however, CERC is not the primary beneficiary and as such, this entity is not consolidated.

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. 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.

(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. CERC’s rate-regulated subsidiaries may collect revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings.

CERC’s rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. As of both December 31, 2013 and 2012, these removal costs of $593 million and $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 2013, 2012 and 2011, CERC capitalized interest and AFUDC of $1 million, $2 million and less than $1 million, respectively.

(h) Income Taxes

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

(i) Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are 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 $25 million and $23 million at December 31, 2013 and 2012, respectively. The provision for doubtful accounts in CERC’s Statements of Consolidated Income for 2013, 2012 and 2011 was $20 million, $15 million and $25 million, respectively.

(j) Inventory

Inventory consists principally of materials and supplies and natural gas. Materials and supplies are valued at the lower of average cost or market. Materials and supplies are recorded to inventory when purchased and subsequently charged to expense or capitalized to plant when installed. Natural gas inventories of CERC’s Energy 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 2013, 2012 and 2011, CERC recorded $4 million, $4 million and $11 million, respectively, in write-downs of natural gas inventory to the lower of average cost or market.



	December 31,
	2013		2012
	(in millions)
Materials and supplies	$	34	$	83
Natural gas	145		145
Total inventory	$	179	$	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

In February 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income” (ASU 2013-02). The objective of ASU 2013-02 is to improve the transparency of changes in other comprehensive income and items reclassified out of Accumulated Other Comprehensive Income in financial statements. This new guidance is effective for a reporting entity's first reporting period beginning after December 15, 2012 and should be applied prospectively. CERC's adoption of this new guidance on January 1, 2013 did not have a material impact on its financial position, results of operations or cash flows.

In December 2011 and January 2013, the FASB issued Accounting Standards Update No. 2011-11, “Disclosures About Offsetting Assets and Liabilities” (ASU 2011-11) and No. 2013-01, “Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities” (ASU 2013-01), respectively. The objective of ASU 2011-11 is to enhance disclosures about the nature of an entity's rights of setoff and related arrangements associated with its financial instruments and derivative instruments. The objective of ASU 2013-01 is to clarify which instruments and transactions are subject to ASU 2011-11. Both ASU 2011-11 and ASU 2013-01 are effective for a reporting entity's first reporting period beginning on or after January 1, 2013 and should be applied retrospectively. CERC's adoption of this new guidance on January 1, 2013 did not have a material impact on its financial position, results of operations or cash flows.

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

(o) Other Current Assets and Liabilities

Included in other current assets on the Consolidated Balance Sheets at December 31, 2013 and 2012 were $4 million and $12 million, respectively, of margin deposits and $22 million and $86 million, respectively of under-recovered gas cost. Included in other current liabilities on the Consolidated Balance Sheets at December 31, 2013 and 2012 were $42 million and $6 million, respectively, of over-recovered gas cost.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2013

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)	2013				2012
		(in millions)
Natural Gas Distribution	31	$	4,694			$	4,321
Energy Services	26	82				80
Interstate Pipelines	—	—		(1	)	2,803
Field Services	—	—		(1	)	2,359
Other property	13	39				52
Total		4,815				9,615
Accumulated depreciation and amortization:
Natural Gas Distribution		1,324				1,194
Energy Services		28				25
Interstate Pipelines		—				355
Field Services		—				118
Other property		27				22
Total accumulated depreciation and amortization		1,379				1,714
Property, plant and equipment, net		$	3,436			$	7,901


(1)	Following the formation of Enable on May 1, 2013, substantially all of the assets of CERC's former Interstate Pipelines and Field Services business segments are owned by Enable.

(b) Depreciation and Amortization

The following table presents depreciation and amortization expense for 2013, 2012 and 2011:



	Year Ended December 31,
	2013		2012		2011
	(in millions)
Depreciation expense	$	218	$	267	$	244
Amortization expense	12		18		18
Total depreciation and amortization expense	$	230	$	285	$	262

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



	December 31,
	2013			2012
Beginning balance	$	135		$	132
Accretion expense	4			6
Revisions in estimates of cash flows	(38		)	(3		)
Ending balance	$	101		$	135

The decrease of $38 million in the ARO from the revision of estimate in 2013 is primarily attributable to a decrease in the future expected cash flows associated with the retirement of steel pipe. 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, 2013 or 2012.

Goodwill

12 Months Ended

Dec. 31, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill Disclosure [Text Block]

Goodwill

Goodwill by reportable business segment and changes in the carrying amount of goodwill are as follows (in millions):



	December 31, 2011		Impairment Charge		Waskom Acquisition (1)		December 31, 2012		Contributed to Enable (1)		December 31, 2013
Natural Gas Distribution	$	746	$	—	$	—	$	746	$	—	$	746
Interstate Pipelines	579		—		—		579		579		—
Energy Services	335		252		—		83		—		83
Field Services	25		—		24		49		49		—
Other	11		—		—		11		—		11
Total	$	1,696	$	252	$	24	$	1,468	$	628	$	840


(1)	See Note 2(b).

CERC performs its goodwill impairment tests at least annually and evaluates goodwill when events or changes in circumstances indicate that its carrying value 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 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 2013 and determined, based on the results of the first step, that no impairment charge was required for any reportable segment. Other intangibles were not material as of December 31, 2013 and 2012.

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 Energy Services reportable segment.

CERC estimated the value of the Energy 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 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 Energy 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.

- Definition

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

+ References + Details

Regulatory Matters

12 Months Ended

Dec. 31, 2013

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, 2013 and 2012:



	December 31,
	2013			2012
	(in millions)
Regulatory assets in other long-term assets (1)	$	100		$	105
Regulatory liabilities	(642		)	(619		)
Net	$	(542	)	$	(514	)

________________


(1)	Regulatory assets that are not earning a return were not material at December 31, 2013 or 2012.

Employee Benefit Plans

12 Months Ended

Dec. 31, 2013

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 $29 million, $32 million and $30 million for the years ended December 31, 2013, 2012 and 2011, respectively.

In addition to the plan, CERC participates in CenterPoint Energy’s non-qualified benefit restoration plans, which allow participants to receive the benefits to which they would have been entitled under CenterPoint Energy’s non-contributory pension plan except for federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated. The expense associated with the non-qualified pension plan was $2 million for each of the years ended December 31, 2013, 2012 and 2011, respectively.

(b) Savings Plan

CERC participates in CenterPoint Energy’s qualified savings plan, which includes a cash or deferred arrangement under Section 401(k) of the Internal Revenue Code of 1986, as amended. Under the plan, participating employees may contribute a portion of their compensation, on a pre-tax or after-tax basis, generally up to a maximum of 50% of eligible compensation. CERC matches 100% of the first 6% of each employee’s compensation contributed. The matching contributions are fully vested at all times. CenterPoint Energy allocates to CERC the savings plan benefit expense related to CERC’s employees. Savings plan benefit expense was $19 million, $18 million and $17 million for the years ended December 31, 2013, 2012 and 2011, respectively.

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

The net postretirement benefit cost includes the following components:



	Year Ended December 31,
	2013			2012			2011
	(in millions)
Service cost — benefits earned during the period	$	1		$	1		$	1
Interest cost on accumulated benefit obligation	5			5			6
Expected return on plan assets	(1		)	(1		)	(1		)
Amortization of prior service cost	1			2			2
Amortization of net loss	2			3			1
Net postretirement benefit cost	$	8		$	10		$	9

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



	Year Ended December 31,
	2013		2012		2011
Discount rate	3.90	%	4.80	%	5.20	%
Expected return on plan assets	3.10	%	3.10	%	4.50	%

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

Following are reconciliations of CERC’s beginning and ending balances of its postretirement benefit plan’s benefit obligation, plan assets and funded status for 2013 and 2012. The measurement dates for plan assets and obligations were December 31, 2013 and 2012.



	December 31,
	2013			2012
	(in millions, except for actuarial assumptions)
Change in Benefit Obligation
Accumulated benefit obligation, beginning of year	$	133		$	118
Service cost	1			1
Interest cost	5			5
Benefits paid	(13		)	(13		)
Participant contributions	4			4
Medicare reimbursement	2			2
Actuarial (gain) loss	(16		)	16
Accumulated benefit obligation, end of year	$	116		$	133
Change in Plan Assets
Plan assets, beginning of year	$	24		$	22
Benefits paid	(13		)	(13		)
Employer contributions	9			9
Participant contributions	4			4
Actual investment return	2			2
Plan assets, end of year	$	26		$	24
Amounts Recognized in Balance Sheets
Current liabilities-other	$	(7	)	$	(7	)
Other liabilities-benefit obligations	(83		)	(102		)
Net liability, end of year	$	(90	)	$	(109	)
Actuarial Assumptions
Discount rate	4.75		%	3.90		%
Expected long-term return on assets	3.10		%	3.10		%
Healthcare cost trend rate assumed for the next year - Pre 65	7.00		%	9.00		%
Healthcare cost trend rate assumed for the next year - Post 65	7.50		%	9.00		%
Prescription cost trend rate assumed for the next year	7.00		%	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	2018			2017
Year that the prescription drug rate reaches the ultimate trend rate	2018			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, medical costs are assumed to increase to 7.00% and 7.50% for the pre-65 and post-65 retirees, respectively, and the prescription cost is assumed to increase 7.00% during 2014, after which this rate decreases until reaching the ultimate trend rate of 5.50% in 2018.

CERC's changes in accumulated comprehensive income related to postretirement and other postemployment plans are as follows (in millions):



	Year Ended December 31, 2013
Beginning Balance	$	(1	)
Other comprehensive income before reclassifications (1)	10
Amounts reclassified from accumulated other comprehensive income:
Prior service cost (2)	1
Actuarial gains (2)	1
Total reclassifications from accumulated other comprehensive income	2
Tax expense	(6		)
Net current period other comprehensive income	6
Ending Balance	$	5

________________


(1)	Total other comprehensive income related to the re-measurement of pension, postretirement and other postemployment plans.


(2)	These accumulated other comprehensive components are included in the computation of net periodic cost.

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



	December 31,
	2013			2012
	(in millions)
Unrecognized actuarial loss	$	9		$	20
Unrecognized prior service cost	1			2
Total recognized in accumulated other comprehensive loss	10			22
Less: deferred tax benefit (1)	(15		)	(21		)
Net amount recognized in accumulated other comprehensive (income) loss	$	(5	)	$	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 2013 are as follows:



	Postretirement Benefits
	(in millions)
Net gain	$	11
Amortization of prior service cost	1
Total recognized in other comprehensive income	$	12

The total expense recognized in net periodic costs and other comprehensive income was $4 million for postretirement benefits for the year ended December 31, 2013.

The amounts in accumulated other comprehensive loss expected to be recognized as components of net periodic benefit cost during 2014 are as follows:



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

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	$	2	$	2
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, 2013 and 2012, by asset category are as follows:



	Fair Value Measurements at December 31, 2013 (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)	$	26	$	26	$	—	$	—
Total	$	26	$	26	$	—	$	—

________________


(1)	73% of the amount invested in mutual funds was in fixed income securities; 20% was in U.S. equities and 7% 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 $7 million to its postretirement benefits plan in 2014. The following benefit payments are expected to be made by the postretirement benefit plan:



	Postretirement Benefit Plan
	Benefit Payments		Medicare Subsidy Receipts
	(in millions)
2014	$	10	$	(2	)
2015	10		(2		)
2016	11		(2		)
2017	11		(2		)
2018	12		(3		)
2019-2023	63		(17		)

(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 expense of $1 million, $5 million and $4 million for the years ended December 31, 2013, 2012 and 2011, respectively. Amounts relating to postemployment benefits included in “Benefit Obligations” in the accompanying Consolidated Balance Sheets at December 31, 2013 and 2012, were $13 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 2013, 2012 and 2011, the benefit expense relating to these plans was less than $1 million each year. Amounts relating to deferred compensation plans included in “Benefit Obligations” in the accompanying Consolidated Balance Sheets at December 31, 2013 and 2012 were $3 million and $2 million, respectively.

(f) Other Employee Matters

As of December 31, 2013, approximately 28% of CERC's employees were covered by collective bargaining agreements.

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2013
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 $38 million and $779 million at December 31, 2013 and 2012, respectively, which are included in accounts and notes payable —affiliated companies in the Consolidated Balance Sheets. At December 31, 2013, CERC’s money pool borrowings had a weighted-average interest rate of 0.03%. CERC had net interest expense related to affiliate borrowings of $2 million, $4 million and less than $1 million for the years ended December 31, 2013, 2012 and 2011, respectively. CenterPoint Energy provides some corporate services to CERC. The costs of services have been charged directly to CERC using methods that management believes are reasonable. These methods include negotiated usage rates, dedicated asset assignment and proportionate corporate formulas based on operating expenses, assets, gross margin, employees and a composite of assets, gross margin and employees. These charges are not necessarily indicative of what would have been incurred had CERC not been an affiliate of CenterPoint Energy. Amounts charged to CERC for these services were $117 million, $163 million and $164 million for 2013, 2012 and 2011, respectively, and are included primarily in operation and maintenance expenses. No dividends were paid to the parent in 2013, 2012 and 2011.

- 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 + Details

Derivative Instruments

12 Months Ended

Dec. 31, 2013

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.

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

In 2013 and 2012, CenterPoint Energy entered into heating-degree day swaps for certain Gas Operations jurisdictions to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the winter heating season. The swaps are based on ten-year normal weather. During the years ended December 31, 2013, 2012 and 2011, CERC recognized losses of $16 million, gains of $8 million and losses of less than $1 million, respectively, related to these swaps. 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, 2013 and 2012, while the last table provides a breakdown of the related income statement impacts for the years ending December 31, 2013, 2012 and 2011.



Fair Value of Derivative Instruments
	December 31, 2013
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	$	28	$	4
Natural gas derivatives (1) (3)	Other Assets: Non-trading derivative assets	10		—
Natural gas derivatives (1) (3)	Current Liabilities: Non-trading derivative liabilities	4		21
Natural gas derivatives (1) (3)	Other Liabilities: Non-trading derivative liabilities	1		5
Total		$	43	$	30

________________


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 607 Bcf or a net 46 Bcf long position. Of the net long position, basis swaps constitute 99 Bcf.


(2)	The $28 million Derivative Current Asset includes $1 million related to physical forwards purchased from Enable.

(3)

Natural gas contracts are presented on a net basis in the Consolidated Balance Sheets. Natural gas contracts are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Consolidated Balance Sheets. The net of total non-trading derivative assets and liabilities was a $13 million asset as shown on CERC’s Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above offset by collateral netting of less than $1 million.



Offsetting of Natural Gas Derivative Assets and Liabilities
	December 31, 2013
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	32		$	(8	)	$	24
Other Assets: Non-trading derivative assets	11			(1		)	10
Current Liabilities: Non-trading derivative liabilities	(25		)	8			(17		)
Other Liabilities: Non-trading derivative liabilities	(5		)	1			(4		)
Total	$	13		$	—		$	13

________________


(1)	Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.


(2)	The derivative assets and liabilities on the Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.



Fair Value of Derivative Instruments
	December 31, 2012
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Natural gas derivatives (1) (2)	Current Assets: Non-trading derivative assets	$	37	$	1
Natural gas derivatives (1) (2)	Other Assets: Non-trading derivative assets	6		—
Natural gas derivatives (1) (2)	Current Liabilities: Non-trading derivative liabilities	5		27
Natural gas derivatives (1) (2)	Other Liabilities: Non-trading derivative liabilities	1		4
Total		$	49	$	32

________________


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 489 billion cubic feet (Bcf) or a net 101 Bcf long position. Of the net long position, basis swaps constitute 73 Bcf.

(2)

Natural gas contracts are presented on a net basis in the Consolidated Balance Sheets. Natural gas contracts are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Consolidated Balance Sheets. The net of total non-trading derivative assets and liabilities was a $26 million asset as shown on CERC’s Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above offset by collateral netting of $9 million.



Offsetting of Natural Gas Derivative Assets and Liabilities
	December 31, 2012
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	42		$	(6	)	$	36
Other Assets: Non-trading derivative assets	7			(1		)	6
Current Liabilities: Non-trading derivative liabilities	(28		)	14			(14		)
Other Liabilities: Non-trading derivative liabilities	(4		)	2			(2		)
Total	$	17		$	9		$	26

________________


(1)	Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.


(2)	The derivative assets and liabilities on the Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.

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	2013		2012			2011
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenue	$	11	$	43		$	102
Natural gas derivatives (1) (2)	Gains (Losses) in Expense: Natural Gas	10		(63		)	(144		)
Total		$	21	$	(20	)	$	(42	)

________________


(1)	The Gains (Losses) in Expense: Natural Gas includes $(2) million during the year ended December 31, 2013 related to physical forwards purchased from Enable.


(2)	The Gains (Losses) in Expense: Natural Gas includes $-0-, $(38) million and $(107) million of costs in 2013, 2012 and 2011, respectively, associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered through purchased gas adjustments.

CERC enters into financial derivative contracts containing material adverse change provisions. These provisions could require CERC to post additional collateral if the Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc. credit ratings of CERC are downgraded. The total fair value of the derivative instruments that contain credit risk contingent features that are in a net liability position at December 31, 2013 and 2012 was $1 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, 2013 and 2012. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at December 31, 2013 and 2012, $1 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, 2013 and 2012 (in millions):



	December 31, 2013				December 31, 2012
	Investment Grade(1)		Total		Investment Grade(1)		Total
Energy marketers	$	1	$	4	$	1	$	1
Financial institutions	1		9		—		—
Retail end users (2)	1		21		—		41
Total	$	3	$	34	$	1	$	42

________________

(1)

“Investment grade” is primarily determined using publicly available credit ratings and considering credit support (such as parent company guarantees) 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 derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6441202&loc=d3e80720-113993

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5624171-113959

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

Fair Value Measurements

12 Months Ended

Dec. 31, 2013

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 $3.79-$4.94 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 0-53%) 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.

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, 2013, 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, 2013 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, 2013
	(in millions)
Assets
Corporate equities	$	2	$	—	$	—	$	—		$	2
Investments, including money market funds	11		—		—		—			11
Natural gas derivatives (2)	5		33		5		(9		)	34
Total assets	$	18	$	33	$	5	$	(9	)	$	47
Liabilities
Natural gas derivatives	$	1	$	27	$	2	$	(9	)	$	21
Total liabilities	$	1	$	27	$	2	$	(9	)	$	21

________________


(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 less than $1 million posted with the same counterparties.


(2)	The (Level 2) Natural gas derivative assets of $33 million include $1 million related to physical forwards purchased from Enable.



	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,
	2013			2012			2011

Beginning balance	$	2		$	6		$	3
Total gains (1)	3			3			6
Total settlements (1)	(3		)	(6		)	(3		)
Total purchases	—			—			2
Transfers out of Level 3	—			(1		)	(2		)
Transfers into Level 3	1			—			—
Ending balance (2)	$	3		$	2		$	6
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	2		$	1		$	5

________


(1)	During 2013, 2012 and 2011, CERC did not have Level 3 unrealized gains (losses) or settlements related to price stabilization activities of the Natural Gas Distribution business segment.


(2)	During 2013, 2012 and 2011, CERC did not have significant Level 3 sales.

Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents and short-term borrowings are estimated to be approximately equivalent to carrying amounts and have been excluded from the table below. 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 using market interest rates on the applicable dates. These assets and liabilities, which are not measured at fair value in the Consolidated Balance Sheets but for which the fair value is disclosed, would be classified as Level 1 in the fair value hierarchy.



	December 31, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial assets:
Notes receivable - affiliated companies	$	363	$	363	$	—	$	—
Financial liabilities:
Long-term debt	$	2,240	$	2,466	$	2,641	$	3,094

- Definition

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

+ References + Details

Unconsolidated Affiliates (Notes)

12 Months Ended

Dec. 31, 2013

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments and Joint Ventures Disclosure [Text Block]

Unconsolidated Affiliates

As discussed in Note 2, on May 1, 2013 (the Closing Date) CERC Corp., OGE and ArcLight closed on the formation of Enable. Enable owns CenterPoint Midstream, which consists of substantially all of CERC Corp.’s former Interstate Pipelines and Field Services business segments. As a result, CERC no longer has Interstate Pipelines or Field Services business segments. Equity earnings associated with CERC's interest in Enable and equity earnings associated with its retained 25.05% interest in SESH are now reported under the Midstream Investments segment. For a further description of CERC's reportable business segments, see Note 15.

The formation of Enable by CERC has been considered a contribution of in-substance real estate to a limited partnership as the businesses are composed of, and reliant upon, substantial real estate assets and integral equipment. Real estate assets and integral equipment primarily includes gas transmission pipelines, compressor station equipment, rights of way, storage and processing assets and long-term customer contracts. Accordingly, CERC did not recognize a gain or loss upon contribution and recorded its investment in Enable using the equity method of accounting based on the historical cost of the contributed assets and liabilities as of the Closing Date. Approximately $5.8 billion of assets (which includes $4.7 billion in property, plant and equipment, net, $629 million in goodwill and $197 million for the 24.95% investment in SESH) and $1.5 billion of liabilities (which includes the three-year unsecured term loan facility (Term Loan) and the indebtedness owed to CERC, both discussed below, of $1.05 billion and $363 million, respectively) were contributed by CERC Corp. CERC has the ability to significantly influence the operating and financial policies of Enable and, accordingly, recorded an equity method investment, at the historical costs of net assets contributed, of $4.3 billion in Enable on the Closing Date. Pursuant to the MFA, CERC retained certain assets and liabilities historically held by CenterPoint Midstream such as balances relating to federal income taxes and benefit plan obligations.

CERC’s investment in Enable is considered to be a VIE because the power to direct the activities that most significantly impact Enable’s economic performance does not reside with the holders of equity investment at risk. However, CERC is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable. Under the equity method, CERC's investment will be adjusted each period for contributions made, distributions received, CERC’s share of Enable’s comprehensive income and accretion of any basis difference. CERC’s maximum exposure to loss related to Enable is limited to its equity investment as presented in the Consolidated Balance Sheet at December 31, 2013 and its guarantee of Enable’s $1.05 billion Term Loan as discussed in Note 13. CERC evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

Effective on the Closing Date, CenterPoint Energy and Enable entered into a Services Agreement, Employee Transition Agreement, Transitional Services Agreement and other agreements (collectively, Transition Agreements) whereby CERC agreed to provide certain support services to Enable such as accounting, legal, risk management and treasury functions for an initial term ending on April 30, 2016. The support services automatically extend year-to-year at the end of the initial term, unless terminated by Enable with at least 90 days’ notice. Enable may terminate these support services at any time with 180 days’ notice if approved by the board of Enable's general partner. Additionally, CERC agreed to provide seconded employees to Enable to support its operations for an initial term ending on December 31, 2014, unless revised by mutual agreement with CenterPoint Energy, OGE and Enable prior to that date. CERC did not transfer any employees to Enable at formation of the partnership or at any time during the year ended December 31, 2013. CERC billed Enable for reimbursement of transitional services, including the costs of seconded employees, of $119 million during the year ended December 31, 2013 under the Transition Agreements. Actual transitional services costs are recorded net of reimbursements received from Enable. CERC had accounts receivable from Enable of $24 million at December 31, 2013 for amounts billed for transitional services, including the cost of seconded employees.

Enable, at its discretion, has the right to select and offer employment to seconded employees from CERC. As of December 31, 2013, CERC determined it cannot reasonably estimate the impact of the costs associated with the termination of employees related to the formation of Enable or transfer of employees from CERC to Enable, including the impact of the changes to the actuarial determination of employee benefit plan obligations. Pursuant to the Transition Agreements, Enable has agreed to reimburse CERC for severance and termination costs related to the termination of CERC's seconded employees, including any potential benefit-related costs, regardless of whether such seconded employees are offered employment by Enable.

On the Closing Date, Enable entered into a $1.05 billion three-year senior unsecured term loan facility (the Term Loan) with third parties and repaid $1.05 billion of affiliated notes payable (Affiliated Notes Payable) owed to CERC. CERC provided a guarantee of Enable's obligations under the Term Loan. The guarantee is subordinated to all senior debt of CERC. Certain of the entities contributed to Enable by CERC are obligated on approximately $363 million of indebtedness owed to CERC bearing interest at an annual rate of 2.10% to 2.45% and scheduled to mature in 2017. CERC recognized interest income of $5 million for the period May 1, 2013 to December 31, 2013 on its notes receivable of $363 million due from Enable.

CERC has certain put rights, and Enable has certain call rights, exercisable with respect to the 25.05% interest in SESH retained by CERC, under which CERC would contribute its retained interest in SESH, in exchange for a specified number of limited partnership units in Enable and a cash payment, payable either from CERC to Enable or from Enable to CERC, for changes in the value of SESH. CERC can exercise its first put right in May 2014 pursuant to which CERC would contribute an additional 24.95% interest in SESH to Enable.

For the period May 1, 2013 to December 31, 2013, CERC incurred natural gas expenses, including transportation and storage costs, of $123 million for transactions with Enable. CERC had accounts payable to Enable of $22 million at December 31, 2013 from such transactions.

As of December 31, 2013, CERC held an approximate 58.3% limited partner interest in Enable and a 25.05% interest in SESH.

Investment in Unconsolidated Affiliates:



	December 31,
	2013		2012

Enable	$	4,319	$	—
SESH (1)	199		404
Other	—		1
Total	$	4,518	$	405


(1)	On May 1, 2013, CERC contributed a 24.95% interest in SESH to Enable, leaving CERC with a 25.05% interest in SESH.

Equity in Earnings of Unconsolidated Affiliates, net:



	Year Ended December 31,
	2013		2012		2011
	(in millions)
Enable	$	173	$	—	$	—
SESH ⁽¹⁾	15		26		21
Waskom ⁽²⁾	—		5		9
Total	$	188	$	31	$	30


(1)	On May 1, 2013, CERC contributed a 24.95% interest in SESH to Enable, leaving CERC with a 25.05% interest in SESH.


(2)	On July 31, 2012, Waskom became a wholly owned subsidiary of CenterPoint Energy. Beginning on August 1, 2012, Waskom’s operating results are consolidated on the Statements of Consolidated Income. On May 1, 2013, CenterPoint Energy contributed Waskom to Enable.

Summarized income information for Enable from formation on May 1, 2013 through December 31, 2013 is as follows (in millions):



Operating revenues	$	2,123
Cost of sales, excluding depreciation and amortization	1,241
Operating income	322
Net income attributable to Enable	289

CERC's approximate 58.3% interest	$	168
Basis difference accretion gain	5
CERC's approximate 58.3% interest, net	$	173

Summarized balance sheet information for Enable as of December 31, 2013 is as follows (in millions):



Current assets	$	549
Non-current assets	10,683
Current liabilities	720
Non-current liabilities	2,331
Noncontrolling interest	33
Enable Partners' Capital	8,148

CERC's approximate 58.3% interest	$	4,753
CERC's basis difference	(434		)
CERC's investment in Enable	$	4,319

Summarized basis difference information for Enable is as follows (in millions):



Basis difference attributable to goodwill as of May 1, 2013 (1)	$	229
Basis difference to be accreted over 30 years as of May 1, 2013	210
Total basis difference as of May 1, 2013	439

Accumulated accretion of basis difference as of December 31, 2013	(5		)
CERC's basis difference in Enable as of December 31, 2013	$	434


(1)	This difference related to CERC’s proportionate share of Enable’s goodwill arising from its acquisition of Enogex, and therefore will not be recognized by CERC.

Enable concluded that the formation of Enable is considered a business combination, and CenterPoint Midstream is the acquirer for accounting purposes. Under this method, the fair value of the consideration paid by CenterPoint Midstream for Enogex is allocated to the assets acquired and liabilities assumed on the Closing Date based on their fair value. Enogex’s assets, liabilities and equity were accordingly adjusted to estimated fair value as of May 1, 2013. Determining the fair value of assets and liabilities is judgmental in nature and often involves the use of significant estimates and assumptions. Enable used appraisers to assist in the determination of the estimated fair value of certain assets and liabilities contributed by Enogex.

Cash distributions received from Enable and SESH were approximately $106 million and $23 million, respectively, during the year ended December 31, 2013.

Short-term Borrowings and Long-term Debt

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Short-term Borrowings and Long-term Debt



	December 31, 2013					December 31, 2012
	Long-Term			Current(1)		Long-Term			Current(1)
	(in millions)
Short-term borrowings:
Inventory financing	$	—		$	43	$	—		$	38
Total short-term borrowings	—			43		—			38
Long-term debt:
Senior notes 4.50% to 6.625% due 2016 to 2041	2,168			—		2,328			365
Commercial paper (2)	118			—		—			—
Unamortized discount and premium	(46		)	—		(52		)	—
Total long-term debt	2,240			—		2,276			365
Total debt	$	2,240		$	43	$	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 $43 million and $38 million as of December 31, 2013 and 2012, respectively.


(b)	Long-term Debt

Debt Repayments. In April 2013, CERC Corp. retired approximately $365 million aggregate principal amount of its 7.875% senior notes at their maturity. The retirement of senior notes was financed by CERC Corp. with the issuance of commercial paper. In May 2013, CERC Corp. applied proceeds from Enable's May 1, 2013 debt repayment of $1.05 billion to the repayment of $357 million aggregate principal amount of its commercial paper and to the May 31, 2013 redemption of $160 million aggregate principal amount of its 5.95% senior notes due January 15, 2014 at 103.419% of their aggregate principal amount.

Revolving Credit Facility. As of December 31, 2013 and 2012, CERC had the following revolving credit facility and utilization of such facility (in millions):



December 31, 2013								December 31, 2012
Size of Facility		Loans		Letters of Credit		Commercial Paper		Size of Facility		Loans		Letters of Credit		Commercial Paper
$	600	$	—	$	—	$	118	$	950	$	—	$	—	$	—

CERC Corp.’s $600 million credit facility, which is scheduled to terminate September 9, 2018, can be drawn at the London Interbank Offered Rate plus 150 basis points based on CERC Corp.’s current credit ratings. The revolving credit facility contains a financial covenant which limits CERC's consolidated debt to an amount not to exceed 65% of its consolidated capitalization. CERC Corp. was in compliance with all debt covenants as of December 31, 2013.

Maturities. CERC’s consolidated maturities of long-term debt are $-0- in 2014, $-0- in 2015, $325 million in 2016, $250 million in 2017 and $418 million in 2018.

Income Taxes

12 Months Ended

Dec. 31, 2013

Income Taxes [Abstract]

Income Taxes

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



	Year Ended December 31,
	2013		2012		2011
	(in millions)
Current income tax expense:
Federal	$	5	$	—	$	34
State	9		1		9
Total current expense	14		1		43
Deferred income tax expense:
Federal	350		198		140
State	7		47		4
Total deferred expense	357		245		144
Total income tax expense	$	371	$	246	$	187

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



	Year Ended December 31,
	2013			2012			2011
	(in millions)
Income before income taxes	$	435		$	383		$	503
Federal statutory income tax rate	35		%	35		%	35		%
Expected federal income tax expense	152			134			176
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	23			31			9
Increase (decrease) in settled and uncertain income tax positions	(2		)	(7		)	1
Tax effect related to the formation of Enable Midstream Partnership	198			—			—
Goodwill impairment	—			88			—
Other, net	—			—			1
Total	219			112			11
Total income tax expense	$	371		$	246		$	187
Effective tax rate	85.3		%	64.2		%	37.2		%

CERC recorded an effective tax rate of 85.3% for 2013 compared to 64.2% for 2012. The increase in the effective tax rate is primarily due to the formation of Enable with deferred tax expense of $225 million related to the book-to-tax basis difference for contributed non-tax deductible goodwill and a tax benefit of $27 million associated with the remeasurement of state deferred taxes at formation. In addition, we recognized a tax benefit of $2 million based on the settlement with the Internal Revenue Service (IRS) of outstanding tax claims for the 2002 and 2003 audit cycles in 2013.

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.

In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. CERC does not expect the adoption of the regulations to have a material impact on its financial position, results of operations or cash flows.

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



	December 31,
	2013			2012
	(in millions)
Deferred tax assets:
Current:
Allowance for doubtful accounts	$	10		$	9
Deferred gas costs	7			—
Other	7			—
Total current deferred tax assets	24			9
Non-current:
Employee benefits	41			49
Loss and credit carryforwards	193			192
Regulatory liabilities, net	—			196
Other	59			51
Total non-current deferred tax assets before valuation allowance	293			488
Valuation allowance	(2		)	(2		)
Total non-current deferred tax assets, net of valuation allowance	291			486
Total deferred tax assets, net of valuation allowance	315			495
Deferred tax liabilities:
Current:
Deferred gas costs	—			25
Other	3			5
Total current deferred tax liabilities	3			30
Non-current:
Depreciation	746			2,033
Regulatory assets, net	17			—
Investment in unconsolidated affiliates	1,590			—
Other	20			129
Total non-current deferred tax liabilities	2,373			2,162
Total deferred tax liabilities	2,376			2,192
Accumulated deferred income taxes, net	$	2,061		$	1,697

Tax Attribute Carryforwards and Valuation Allowance. At December 31, 2013, CERC has approximately $495 million of federal net operating loss carryforwards which begin to expire in 2031 and approximately $387 million of state net operating loss carryforwards which expire in various years between 2015 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 loss carryforwards may not be fully realized.

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



	December 31,
	2013			2012			2011
	(in millions)
Balance, beginning of year	$	(20	)	$	8		$	11
Tax Positions related to prior years:
Additions	(2		)	—			(1		)
Reductions	—			(27		)	(3		)
Tax Positions related to current year:
Additions	—			—			1
Settlements	22			(1		)	—
Balance, end of year	$	—		$	(20	)	$	8

The net decrease in the total amount of unrecognized tax benefits during 2013 is primarily related to CERC’s IRS settlements related to open claims for tax years 2002 and 2003. During 2013, the IRS completed the examination cycle and settlement for tax years 2010 and 2011. CERC does not expect the change to the amount of unrecognized tax benefits over the twelve months ending December 31, 2014 to have a material impact on financial position, results of operations and cash flows.

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 had approximately $-0-, $-0- and $6 million of unrecognized tax benefits that, if recognized, would affect the effective income tax rate for 2013, 2012 and 2011, respectively. CERC recognizes interest and penalties as a component of income tax expense. CERC recognized approximately $4 million of income tax benefit, $3 million of income tax expense and $0.4 million of income tax expense related to interest on uncertain income tax positions during 2013, 2012 and 2011, respectively. CERC had approximately $11 million and $7 million of interest receivable on uncertain, including settled, income tax positions accrued at December 31, 2013 and 2012, respectively.

Tax Audits and Settlements. CenterPoint Energy's consolidated federal income tax returns have been audited and settled through tax year 2011. CenterPoint Energy is currently in the early stages of examination by the IRS for tax year 2012. 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, 2013.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

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 Energy 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, 2013 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, 2013, minimum payment obligations for natural gas supply commitments are approximately $408 million in 2014, $391 million in 2015, $310 million in 2016, $250 million in 2017, $244 million in 2018 and $120 million after 2018.

(b) Asset Management Agreements

Gas Operations has asset management agreements (AMAs) associated with its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and Texas. Generally, these AMAs 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 AMAs, 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 AMAs based in part on the results of the asset optimization. Gas Operations has an obligation to purchase its winter storage requirements that have been released to the asset manager under these AMAs. The AMAs 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, 2013, which primarily consist of rental agreements for building space, data processing equipment, compression equipment and rights of way (in millions):



2014	$	6
2015	4
2016	3
2017	2
2018	2
2019 and beyond	3
Total	$	20

Total lease expense for all operating leases was $20 million, $26 million and $42 million in 2013, 2012 and 2011, respectively.

(d) 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, Reliant Resources, Inc. (RRI), CenterPoint Energy and its subsidiaries are entitled to be indemnified by RRI and its successors for any losses, including certain 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 guarantee 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 one such case. 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 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 appealed this ruling to the United States Court of Appeals for the Ninth Circuit, which reversed the trial court's dismissal of the plaintiffs' claims. In August 2013, the other defendants filed a petition for review with the U.S. Supreme Court. CenterPoint Energy believes that CES is not a proper defendant in this case and will continue to pursue a dismissal. CenterPoint Energy does not expect the ultimate outcome of this matter 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, 2013, 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, 2013, CERC had collected $6.3 million from insurance companies to be used for future environmental remediation.

In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CERC and CenterPoint Energy do not expect the ultimate outcome of these investigations will have a material adverse impact on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.

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. In 2004 and early 2005, CERC sold its generating business, to which most of these claims relate, to a company which is now an affiliate of NRG. Under the terms of the arrangements regarding separation of the generating business from CERC and its sale of that business, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by the NRG affiliate, but CERC has agreed to continue to defend such claims to the extent they are covered by insurance maintained by CERC, subject to reimbursement of the costs of such defense by the NRG affiliate. 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 its subsidiaries conduct or have conducted operations. Other such sites involving contaminants may be identified in the future. CERC has and expects to continue to remediate identified sites consistent with its legal obligations. From time to time CERC has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, CERC has been named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, CERC does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on CERC’s 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. From time to time, CERC is also a defendant in legal proceedings with respect to claims brought by various plaintiffs against broad groups of participants in the energy industry. 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 CERC’s financial condition, results of operations or cash flows.

(e) Guarantees

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 guarantees 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 guarantees 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 guarantees 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 $58 million as of December 31, 2013. Based on market conditions in the fourth quarter of 2013 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. 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.

CERC Corp. has also provided a guarantee of collection of Enable's obligations under its $1.05 billion Term Loan, which guarantee is subordinated to all senior debt of CERC Corp.

As of December 31, 2013, no amounts have been recorded related to the guarantees discussed above in the Consolidated Balance Sheets.

Unaudited Quarterly Information

12 Months Ended

Dec. 31, 2013

Unaudited Quarterly Information [Abstract]

Quarterly Financial Information [Text Block]

Unaudited Quarterly Information

Summarized quarterly financial data is as follows:



	Year Ended December 31, 2013
	First Quarter		Second Quarter (1)			Third Quarter		Fourth Quarter
	(in millions)
Revenues	$	1,853	$	1,235		$	891	$	1,543
Operating income	250		56			4		91
Net income (loss)	128		(162		)	32		66



	Year Ended December 31, 2012
	First Quarter		Second Quarter		Third Quarter (2)			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


(1)	Effective May 1, 2013, CERC Corp. contributed CenterPoint Midstream to Enable. See Note 2(b) and Note 10 for further discussion on the formation of Enable and CERC’s investment in Enable, respectively.


(2)	See Note 2(b) and Note (4) for further discussion on the acquisition of additional interest in Waskom and the goodwill impairment charge, respectively.

Reportable Business Segments

12 Months Ended

Dec. 31, 2013

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, Energy Services, Midstream Investments 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. Energy Services represents CERC’s non-rate regulated gas sales and services operations. Midstream Investments consists primarily of CERC’s investment in Enable and its retained interest in SESH. The Other Operations business segment includes unallocated corporate costs and inter-segment eliminations.

Prior to May 1, 2013, CERC also reported an Interstate Pipelines business segment, which included CenterPoint Energy’s interstate natural gas pipeline operations, and a Field Services business segment, which included CERC’s non-rate regulated natural gas gathering, processing and treating operations. As previously disclosed, the formation of Enable closed on May 1, 2013. Enable now owns substantially all of CERC’s former Interstate Pipelines and Field Services business segments, except for the retained interest in SESH. As a result, effective May 1, 2013, CERC reports equity earnings associated with its interest in Enable and equity earnings associated with its retained interest in SESH under a new Midstream Investments segment, and no longer has Interstate Pipelines and Field Services reporting segments prospectively. See Note 10 for further discussion on Enable formation.

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, 2013:
Natural Gas Distribution	$	2,837	$	26		$	185	$	263		$	4,976		$	430
Energy Services	2,374		27			5		13			895			3
Interstate Pipelines (1) (3)	133		53			20		72			—			29
Field Services (2) (3)	178		18			20		73			—			16
Midstream Investments (4)	—		—			—		—			4,518			—
Other	—		—			—		(20		)	1,149			—
Reconciling Eliminations	—		(124		)	—		—			(996		)	—
Consolidated	$	5,522	$	—		$	230	$	401		$	10,542		$	478
As of and for the year ended December 31, 2012:
Natural Gas Distribution	$	2,320	$	22		$	173	$	226		$	4,775		$	359
Energy 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
As of and for the year ended December 31, 2011:
Natural Gas Distribution	$	2,823	$	18		$	166	$	226		$	4,636		$	295
Energy Services	2,488		23			5		6			1,089			5
Interstate Pipelines (1)	421		132			54		248			3,867			98
Field Services (2)	370		42			37		189			1,894			201
Other	—		—			—		(7		)	660			—
Reconciling Eliminations	—		(215		)	—		—			(1,459		)	—
Consolidated	$	6,102	$	—		$	262	$	662		$	10,687		$	599

________________

(1)

Interstate Pipelines recorded equity income of $7 million, $26 million and $21 million in the years ended December 31, 2013, 2012 and 2011, respectively, from its 50% interest in SESH, a jointly-owned pipeline. These amounts are included in Equity in earnings of unconsolidated affiliates under the Other Income (Expense) caption. Interstate Pipelines’ investment in SESH was $404 million and $409 million as of December 31, 2012 and 2011, respectively, and is included in Investment in unconsolidated affiliates. As discussed above, effective May 1, 2013, CenterPoint Energy reports equity earnings associated with its interest in Enable and equity earnings associated with its retained interest in SESH under a new Midstream Investments segment, and no longer has an Interstate Pipelines reporting segment prospectively.

(2)

Field Services recorded equity income of $5 million and $9 million for the years ended December 31, 2012 and 2011, respectively, from its 50% interest in a jointly-owned gas processing plant. These amounts are included in Equity in earnings of unconsolidated affiliates under the Other Income (Expense) caption. Field Services’ investment in the jointly-owned gas processing plant was $63 million as of December 31, 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 CenterPoint Energy did not already own. CERC contributed 100% interest in Waskom to Enable on May 1, 2013. Effective May 1, 2013, CERC equity earnings associated with its interest in Enable under a new Midstream Investments segment, and no longer has a Field Services reporting segment prospectively.


(3)	Results reflected in the year ended December 31, 2013 represent only January 2013 through April 2013.


(4)	Midstream Investments reported equity earnings of $173 million from Enable and $8 million of equity earnings from CERC’s retained interest in SESH for the eight months ended December 31, 2013. Included in total assets of Midstream Investments as of December 31, 2013 is $4,319 million related to CERC’s investment in Enable and $199 million related to CERC’s retained interest in SESH.



	Year Ended December 31,
Revenues by Products and Services:	2013		2012		2011
	(in millions)
Retail gas sales	$	4,150	$	3,328	$	4,019
Wholesale gas sales	913		613		1,149
Gas transportation and processing	345		847		824
Energy products and services	114		113		110
Total	$	5,522	$	4,901	$	6,102

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2013
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 also uses the equity method for investments in which it has ownership percentages greater than 50%, when it exercises significant influence, does not have control and is not considered the primary beneficiary, if applicable. On March 14, 2013, CenterPoint Energy entered into a Master Formation Agreement (MFA) with OGE Energy Corp. (OGE) and affiliates of ArcLight Capital Partners, LLC (ArcLight), pursuant to which CenterPoint Energy, OGE and ArcLight agreed to form Enable as a private limited partnership. On May 1, 2013, the parties closed on the formation of Enable. In connection with the closing (i) CERC Corp. converted its direct wholly owned subsidiary, CenterPoint Energy Field Services, LLC, a Delaware limited liability company (CEFS), into a Delaware limited partnership that became Enable, (ii) CERC Corp. contributed to Enable its equity interests in each of CenterPoint Energy Gas Transmission Company, LLC, which has been subsequently renamed Enable Gas Transmission, LLC (EGT), CenterPoint Energy - Mississippi River Transmission, LLC, which has been subsequently renamed Enable Mississippi River Transmission, LLC (MRT), certain of its other midstream subsidiaries (Other CNP Midstream Subsidiaries), and a 24.95% interest in Southeast Supply Header, LLC (SESH and, collectively with CEFS, EGT, MRT and Other CNP Midstream Subsidiaries, CenterPoint Midstream), and (iii) OGE and ArcLight indirectly contributed 100% of the equity interests in Enogex LLC, which has been subsequently renamed Enable Oklahoma Intrastate Transmission, LLC (Enogex), to Enable. As of December 31, 2013, CERC Corp., OGE and ArcLight held approximately 58.3%, 28.5% and 13.2%, respectively, of the limited partner interests in Enable. Enable is equally controlled by CERC Corp. and OGE; each own 50% of the management rights in the general partner of Enable. CERC Corp. and OGE also own a 40% and 60% interest, respectively, in the incentive distribution rights held by the general partner of Enable. The general partner of Enable is currently governed by a board of directors made up of an equal number of representatives designated by each of CERC Corp. and OGE. The investment in Enable is accounted for utilizing the equity method of accounting. As of December 31, 2013, CERC determined that Enable was a variable interest entity (VIE); however, CERC is not the primary beneficiary and as such, this entity is not consolidated. 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. 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.
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. CERC’s rate-regulated subsidiaries may collect revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings. CERC’s rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. As of both December 31, 2013 and 2012, these removal costs of $593 million and $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 2013, 2012 and 2011, CERC capitalized interest and AFUDC of $1 million, $2 million and less than $1 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 $25 million and $23 million at December 31, 2013 and 2012, respectively. The provision for doubtful accounts in CERC’s Statements of Consolidated Income for 2013, 2012 and 2011 was $20 million, $15 million and $25 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 Energy 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 2013, 2012 and 2011, CERC recorded $4 million, $4 million and $11 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 In February 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income” (ASU 2013-02). The objective of ASU 2013-02 is to improve the transparency of changes in other comprehensive income and items reclassified out of Accumulated Other Comprehensive Income in financial statements. This new guidance is effective for a reporting entity's first reporting period beginning after December 15, 2012 and should be applied prospectively. CERC's adoption of this new guidance on January 1, 2013 did not have a material impact on its financial position, results of operations or cash flows. In December 2011 and January 2013, the FASB issued Accounting Standards Update No. 2011-11, “Disclosures About Offsetting Assets and Liabilities” (ASU 2011-11) and No. 2013-01, “Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities” (ASU 2013-01), respectively. The objective of ASU 2011-11 is to enhance disclosures about the nature of an entity's rights of setoff and related arrangements associated with its financial instruments and derivative instruments. The objective of ASU 2013-01 is to clarify which instruments and transactions are subject to ASU 2011-11. Both ASU 2011-11 and ASU 2013-01 are effective for a reporting entity's first reporting period beginning on or after January 1, 2013 and should be applied retrospectively. CERC's adoption of this new guidance on January 1, 2013 did not have a material impact on its financial position, results of operations or cash flows. Management believes the impact of other recently issued standards, which are not yet effective, will not have a material impact on CERC's consolidated financial position, results of operations or cash flows upon adoption.
Other Current Assets and Liabilities	Other Current Assets and Liabilities Included in other current assets on the Consolidated Balance Sheets at December 31, 2013 and 2012 were $4 million and $12 million, respectively, of margin deposits and $22 million and $86 million, respectively of under-recovered gas cost. Included in other current liabilities on the Consolidated Balance Sheets at December 31, 2013 and 2012 were $42 million and $6 million, respectively, of over-recovered gas cost.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Significant Accounting Policies [Abstract]

Schedule of Inventory [Table Text Block]



	December 31,
	2013		2012
	(in millions)
Materials and supplies	$	34	$	83
Natural gas	145		145
Total inventory	$	179	$	228

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, plant and equipment includes the following:



	Weighted Average Useful Lives	December 31,
	(Years)	2013				2012
		(in millions)
Natural Gas Distribution	31	$	4,694			$	4,321
Energy Services	26	82				80
Interstate Pipelines	—	—		(1	)	2,803
Field Services	—	—		(1	)	2,359
Other property	13	39				52
Total		4,815				9,615
Accumulated depreciation and amortization:
Natural Gas Distribution		1,324				1,194
Energy Services		28				25
Interstate Pipelines		—				355
Field Services		—				118
Other property		27				22
Total accumulated depreciation and amortization		1,379				1,714
Property, plant and equipment, net		$	3,436			$	7,901


(1)	Following the formation of Enable on May 1, 2013, substantially all of the assets of CERC's former Interstate Pipelines and Field Services business segments are owned by Enable.

Depreciation And Amortization [Table Text Block]

The following table presents depreciation and amortization expense for 2013, 2012 and 2011:



	Year Ended December 31,
	2013		2012		2011
	(in millions)
Depreciation expense	$	218	$	267	$	244
Amortization expense	12		18		18
Total depreciation and amortization expense	$	230	$	285	$	262

Asset Retirement Obligations

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



	December 31,
	2013			2012
Beginning balance	$	135		$	132
Accretion expense	4			6
Revisions in estimates of cash flows	(38		)	(3		)
Ending balance	$	101		$	135

Goodwill (Tables)

12 Months Ended

Dec. 31, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill



	December 31, 2011		Impairment Charge		Waskom Acquisition (1)		December 31, 2012		Contributed to Enable (1)		December 31, 2013
Natural Gas Distribution	$	746	$	—	$	—	$	746	$	—	$	746
Interstate Pipelines	579		—		—		579		579		—
Energy Services	335		252		—		83		—		83
Field Services	25		—		24		49		49		—
Other	11		—		—		11		—		11
Total	$	1,696	$	252	$	24	$	1,468	$	628	$	840


(1)	See Note 2(b).

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2013

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, 2013 and 2012:



	December 31,
	2013			2012
	(in millions)
Regulatory assets in other long-term assets (1)	$	100		$	105
Regulatory liabilities	(642		)	(619		)
Net	$	(542	)	$	(514	)

________________


(1)	Regulatory assets that are not earning a return were not material at December 31, 2013 or 2012.

Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2013

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 2014 are as follows:



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

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)
2014	$	10	$	(2	)
2015	10		(2		)
2016	11		(2		)
2017	11		(2		)
2018	12		(3		)
2019-2023	63		(17		)

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%



	December 31,
	2013			2012
	(in millions, except for actuarial assumptions)
Change in Benefit Obligation
Accumulated benefit obligation, beginning of year	$	133		$	118
Service cost	1			1
Interest cost	5			5
Benefits paid	(13		)	(13		)
Participant contributions	4			4
Medicare reimbursement	2			2
Actuarial (gain) loss	(16		)	16
Accumulated benefit obligation, end of year	$	116		$	133
Change in Plan Assets
Plan assets, beginning of year	$	24		$	22
Benefits paid	(13		)	(13		)
Employer contributions	9			9
Participant contributions	4			4
Actual investment return	2			2
Plan assets, end of year	$	26		$	24
Amounts Recognized in Balance Sheets
Current liabilities-other	$	(7	)	$	(7	)
Other liabilities-benefit obligations	(83		)	(102		)
Net liability, end of year	$	(90	)	$	(109	)
Actuarial Assumptions
Discount rate	4.75		%	3.90		%
Expected long-term return on assets	3.10		%	3.10		%
Healthcare cost trend rate assumed for the next year - Pre 65	7.00		%	9.00		%
Healthcare cost trend rate assumed for the next year - Post 65	7.50		%	9.00		%
Prescription cost trend rate assumed for the next year	7.00		%	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	2018			2017
Year that the prescription drug rate reaches the ultimate trend rate	2018			2017

The net postretirement benefit cost includes the following components:



	Year Ended December 31,
	2013			2012			2011
	(in millions)
Service cost — benefits earned during the period	$	1		$	1		$	1
Interest cost on accumulated benefit obligation	5			5			6
Expected return on plan assets	(1		)	(1		)	(1		)
Amortization of prior service cost	1			2			2
Amortization of net loss	2			3			1
Net postretirement benefit cost	$	8		$	10		$	9

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



	Year Ended December 31,
	2013		2012		2011
Discount rate	3.90	%	4.80	%	5.20	%
Expected return on plan assets	3.10	%	3.10	%	4.50	%



	Year Ended December 31, 2013
Beginning Balance	$	(1	)
Other comprehensive income before reclassifications (1)	10
Amounts reclassified from accumulated other comprehensive income:
Prior service cost (2)	1
Actuarial gains (2)	1
Total reclassifications from accumulated other comprehensive income	2
Tax expense	(6		)
Net current period other comprehensive income	6
Ending Balance	$	5

________________


(1)	Total other comprehensive income related to the re-measurement of pension, postretirement and other postemployment plans.


(2)	These accumulated other comprehensive components are included in the computation of net periodic cost.

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



	December 31,
	2013			2012
	(in millions)
Unrecognized actuarial loss	$	9		$	20
Unrecognized prior service cost	1			2
Total recognized in accumulated other comprehensive loss	10			22
Less: deferred tax benefit (1)	(15		)	(21		)
Net amount recognized in accumulated other comprehensive (income) loss	$	(5	)	$	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 2013 are as follows:



	Postretirement Benefits
	(in millions)
Net gain	$	11
Amortization of prior service cost	1
Total recognized in other comprehensive income	$	12

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	$	2	$	2
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, 2013 and 2012, by asset category are as follows:



	Fair Value Measurements at December 31, 2013 (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)	$	26	$	26	$	—	$	—
Total	$	26	$	26	$	—	$	—

________________


(1)	73% of the amount invested in mutual funds was in fixed income securities; 20% was in U.S. equities and 7% 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.

Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2013

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, 2013
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	$	28	$	4
Natural gas derivatives (1) (3)	Other Assets: Non-trading derivative assets	10		—
Natural gas derivatives (1) (3)	Current Liabilities: Non-trading derivative liabilities	4		21
Natural gas derivatives (1) (3)	Other Liabilities: Non-trading derivative liabilities	1		5
Total		$	43	$	30

________________


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 607 Bcf or a net 46 Bcf long position. Of the net long position, basis swaps constitute 99 Bcf.


(2)	The $28 million Derivative Current Asset includes $1 million related to physical forwards purchased from Enable.

(3)



Offsetting of Natural Gas Derivative Assets and Liabilities
	December 31, 2013
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	32		$	(8	)	$	24
Other Assets: Non-trading derivative assets	11			(1		)	10
Current Liabilities: Non-trading derivative liabilities	(25		)	8			(17		)
Other Liabilities: Non-trading derivative liabilities	(5		)	1			(4		)
Total	$	13		$	—		$	13

________________


(1)	Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.


(2)	The derivative assets and liabilities on the Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.



Fair Value of Derivative Instruments
	December 31, 2012
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Natural gas derivatives (1) (2)	Current Assets: Non-trading derivative assets	$	37	$	1
Natural gas derivatives (1) (2)	Other Assets: Non-trading derivative assets	6		—
Natural gas derivatives (1) (2)	Current Liabilities: Non-trading derivative liabilities	5		27
Natural gas derivatives (1) (2)	Other Liabilities: Non-trading derivative liabilities	1		4
Total		$	49	$	32

________________


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 489 billion cubic feet (Bcf) or a net 101 Bcf long position. Of the net long position, basis swaps constitute 73 Bcf.

(2)

Natural gas contracts are presented on a net basis in the Consolidated Balance Sheets. Natural gas contracts are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Consolidated Balance Sheets. The net of total non-trading derivative assets and liabilities was a $26 million asset as shown on CERC’s Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above offset by collateral netting of $9 million.



Offsetting of Natural Gas Derivative Assets and Liabilities
	December 31, 2012
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	42		$	(6	)	$	36
Other Assets: Non-trading derivative assets	7			(1		)	6
Current Liabilities: Non-trading derivative liabilities	(28		)	14			(14		)
Other Liabilities: Non-trading derivative liabilities	(4		)	2			(2		)
Total	$	17		$	9		$	26

________________


(1)	Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.


(2)	The derivative assets and liabilities on the Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.

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	2013		2012			2011
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenue	$	11	$	43		$	102
Natural gas derivatives (1) (2)	Gains (Losses) in Expense: Natural Gas	10		(63		)	(144		)
Total		$	21	$	(20	)	$	(42	)

________________


(1)	The Gains (Losses) in Expense: Natural Gas includes $(2) million during the year ended December 31, 2013 related to physical forwards purchased from Enable.


(2)	The Gains (Losses) in Expense: Natural Gas includes $-0-, $(38) million and $(107) million of costs in 2013, 2012 and 2011, 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, 2013				December 31, 2012
	Investment Grade(1)		Total		Investment Grade(1)		Total
Energy marketers	$	1	$	4	$	1	$	1
Financial institutions	1		9		—		—
Retail end users (2)	1		21		—		41
Total	$	3	$	34	$	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.

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2013

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, 2013
	(in millions)
Assets
Corporate equities	$	2	$	—	$	—	$	—		$	2
Investments, including money market funds	11		—		—		—			11
Natural gas derivatives (2)	5		33		5		(9		)	34
Total assets	$	18	$	33	$	5	$	(9	)	$	47
Liabilities
Natural gas derivatives	$	1	$	27	$	2	$	(9	)	$	21
Total liabilities	$	1	$	27	$	2	$	(9	)	$	21

________________


(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 less than $1 million posted with the same counterparties.


(2)	The (Level 2) Natural gas derivative assets of $33 million include $1 million related to physical forwards purchased from Enable.



	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,
	2013			2012			2011

Beginning balance	$	2		$	6		$	3
Total gains (1)	3			3			6
Total settlements (1)	(3		)	(6		)	(3		)
Total purchases	—			—			2
Transfers out of Level 3	—			(1		)	(2		)
Transfers into Level 3	1			—			—
Ending balance (2)	$	3		$	2		$	6
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	2		$	1		$	5

________


(1)	During 2013, 2012 and 2011, CERC did not have Level 3 unrealized gains (losses) or settlements related to price stabilization activities of the Natural Gas Distribution business segment.


(2)	During 2013, 2012 and 2011, CERC did not have significant Level 3 sales.

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



	December 31, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial assets:
Notes receivable - affiliated companies	$	363	$	363	$	—	$	—
Financial liabilities:
Long-term debt	$	2,240	$	2,466	$	2,641	$	3,094

Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2013

Equity Method Investments and Joint Ventures [Abstract]

Summary Investment Holdings [Table Text Block]



	December 31,
	2013		2012

Enable	$	4,319	$	—
SESH (1)	199		404
Other	—		1
Total	$	4,518	$	405


(1)	On May 1, 2013, CERC contributed a 24.95% interest in SESH to Enable, leaving CERC with a 25.05% interest in SESH.

Schedule of Equity in Earning of Unconsolidated Affiliates [Table Text Block]



	Year Ended December 31,
	2013		2012		2011
	(in millions)
Enable	$	173	$	—	$	—
SESH ⁽¹⁾	15		26		21
Waskom ⁽²⁾	—		5		9
Total	$	188	$	31	$	30


(1)	On May 1, 2013, CERC contributed a 24.95% interest in SESH to Enable, leaving CERC with a 25.05% interest in SESH.


(2)	On July 31, 2012, Waskom became a wholly owned subsidiary of CenterPoint Energy. Beginning on August 1, 2012, Waskom’s operating results are consolidated on the Statements of Consolidated Income. On May 1, 2013, CenterPoint Energy contributed Waskom to Enabl

Schedule of Balance Sheet of Unconsolidated Affiliate [Table Text Block]



Current assets	$	549
Non-current assets	10,683
Current liabilities	720
Non-current liabilities	2,331
Noncontrolling interest	33
Enable Partners' Capital	8,148

CERC's approximate 58.3% interest	$	4,753
CERC's basis difference	(434		)
CERC's investment in Enable	$	4,319

Schedule of Income Statements of Unconsolidated Affiliates [Table Text Block]



Operating revenues	$	2,123
Cost of sales, excluding depreciation and amortization	1,241
Operating income	322
Net income attributable to Enable	289

CERC's approximate 58.3% interest	$	168
Basis difference accretion gain	5
CERC's approximate 58.3% interest, net	$	173

Schedule of Basis Difference of Unconsolidated Affiliates [Table Text Block]



Basis difference attributable to goodwill as of May 1, 2013 (1)	$	229
Basis difference to be accreted over 30 years as of May 1, 2013	210
Total basis difference as of May 1, 2013	439

Accumulated accretion of basis difference as of December 31, 2013	(5		)
CERC's basis difference in Enable as of December 31, 2013	$	434

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

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Schedule of Debt [Table Text Block]



	December 31, 2013					December 31, 2012
	Long-Term			Current(1)		Long-Term			Current(1)
	(in millions)
Short-term borrowings:
Inventory financing	$	—		$	43	$	—		$	38
Total short-term borrowings	—			43		—			38
Long-term debt:
Senior notes 4.50% to 6.625% due 2016 to 2041	2,168			—		2,328			365
Commercial paper (2)	118			—		—			—
Unamortized discount and premium	(46		)	—		(52		)	—
Total long-term debt	2,240			—		2,276			365
Total debt	$	2,240		$	43	$	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, 2013 and 2012, CERC had the following revolving credit facility and utilization of such facility (in millions):



December 31, 2013								December 31, 2012
Size of Facility		Loans		Letters of Credit		Commercial Paper		Size of Facility		Loans		Letters of Credit		Commercial Paper
$	600	$	—	$	—	$	118	$	950	$	—	$	—	$	—

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Taxes [Abstract]

Income Tax Expense Disclosure

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



	Year Ended December 31,
	2013		2012		2011
	(in millions)
Current income tax expense:
Federal	$	5	$	—	$	34
State	9		1		9
Total current expense	14		1		43
Deferred income tax expense:
Federal	350		198		140
State	7		47		4
Total deferred expense	357		245		144
Total income tax expense	$	371	$	246	$	187

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,
	2013			2012			2011
	(in millions)
Income before income taxes	$	435		$	383		$	503
Federal statutory income tax rate	35		%	35		%	35		%
Expected federal income tax expense	152			134			176
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	23			31			9
Increase (decrease) in settled and uncertain income tax positions	(2		)	(7		)	1
Tax effect related to the formation of Enable Midstream Partnership	198			—			—
Goodwill impairment	—			88			—
Other, net	—			—			1
Total	219			112			11
Total income tax expense	$	371		$	246		$	187
Effective tax rate	85.3		%	64.2		%	37.2		%

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,
	2013			2012
	(in millions)
Deferred tax assets:
Current:
Allowance for doubtful accounts	$	10		$	9
Deferred gas costs	7			—
Other	7			—
Total current deferred tax assets	24			9
Non-current:
Employee benefits	41			49
Loss and credit carryforwards	193			192
Regulatory liabilities, net	—			196
Other	59			51
Total non-current deferred tax assets before valuation allowance	293			488
Valuation allowance	(2		)	(2		)
Total non-current deferred tax assets, net of valuation allowance	291			486
Total deferred tax assets, net of valuation allowance	315			495
Deferred tax liabilities:
Current:
Deferred gas costs	—			25
Other	3			5
Total current deferred tax liabilities	3			30
Non-current:
Depreciation	746			2,033
Regulatory assets, net	17			—
Investment in unconsolidated affiliates	1,590			—
Other	20			129
Total non-current deferred tax liabilities	2,373			2,162
Total deferred tax liabilities	2,376			2,192
Accumulated deferred income taxes, net	$	2,061		$	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,
	2013			2012			2011
	(in millions)
Balance, beginning of year	$	(20	)	$	8		$	11
Tax Positions related to prior years:
Additions	(2		)	—			(1		)
Reductions	—			(27		)	(3		)
Tax Positions related to current year:
Additions	—			—			1
Settlements	22			(1		)	—
Balance, end of year	$	—		$	(20	)	$	8

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Operating Leases of Lessee Disclosure [Table Text Block]



2014	$	6
2015	4
2016	3
2017	2
2018	2
2019 and beyond	3
Total	$	20

- 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, 2013

Unaudited Quarterly Information [Abstract]

Quarterly financial data

Summarized quarterly financial data is as follows:



	Year Ended December 31, 2013
	First Quarter		Second Quarter (1)			Third Quarter		Fourth Quarter
	(in millions)
Revenues	$	1,853	$	1,235		$	891	$	1,543
Operating income	250		56			4		91
Net income (loss)	128		(162		)	32		66



	Year Ended December 31, 2012
	First Quarter		Second Quarter		Third Quarter (2)			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


(1)	Effective May 1, 2013, CERC Corp. contributed CenterPoint Midstream to Enable. See Note 2(b) and Note 10 for further discussion on the formation of Enable and CERC’s investment in Enable, respectively.


(2)	See Note 2(b) and Note (4) for further discussion on the acquisition of additional interest in Waskom and the goodwill impairment charge, respectively.

Reportable Business Segments (Tables)

12 Months Ended

Dec. 31, 2013

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, 2013:
Natural Gas Distribution	$	2,837	$	26		$	185	$	263		$	4,976		$	430
Energy Services	2,374		27			5		13			895			3
Interstate Pipelines (1) (3)	133		53			20		72			—			29
Field Services (2) (3)	178		18			20		73			—			16
Midstream Investments (4)	—		—			—		—			4,518			—
Other	—		—			—		(20		)	1,149			—
Reconciling Eliminations	—		(124		)	—		—			(996		)	—
Consolidated	$	5,522	$	—		$	230	$	401		$	10,542		$	478
As of and for the year ended December 31, 2012:
Natural Gas Distribution	$	2,320	$	22		$	173	$	226		$	4,775		$	359
Energy 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
As of and for the year ended December 31, 2011:
Natural Gas Distribution	$	2,823	$	18		$	166	$	226		$	4,636		$	295
Energy Services	2,488		23			5		6			1,089			5
Interstate Pipelines (1)	421		132			54		248			3,867			98
Field Services (2)	370		42			37		189			1,894			201
Other	—		—			—		(7		)	660			—
Reconciling Eliminations	—		(215		)	—		—			(1,459		)	—
Consolidated	$	6,102	$	—		$	262	$	662		$	10,687		$	599

________________

(1)

(2)


(3)	Results reflected in the year ended December 31, 2013 represent only January 2013 through April 2013.


(4)	Midstream Investments reported equity earnings of $173 million from Enable and $8 million of equity earnings from CERC’s retained interest in SESH for the eight months ended December 31, 2013. Included in total assets of Midstream Investments as of December 31, 2013 is $4,319 million related to CERC’s investment in Enable and $199 million related to CERC’s retained interest in SESH.

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



	Year Ended December 31,
Revenues by Products and Services:	2013		2012		2011
	(in millions)
Retail gas sales	$	4,150	$	3,328	$	4,019
Wholesale gas sales	913		613		1,149
Gas transportation and processing	345		847		824
Energy products and services	114		113		110
Total	$	5,522	$	4,901	$	6,102

Schedule II Valuation and Qualifying Accounts (Tables)

12 Months Ended

Dec. 31, 2013

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, 2013



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, 2013:
Accumulated provisions:
Uncollectible accounts receivable	$	23	$	20		$	—	$	18	$	25
Deferred tax asset valuation allowance	2		—			—		—		2
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

________________


(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.

Background (Details)	Dec. 31, 2013
Natural Gas Distribution [Member]
Number of States in which Entity Operates	6
Energy Services [Member]
Number of States in which Entity Operates	21
Enable Midstream Partners [Member]
Equity Method Investment, Ownership Percentage	58.30%

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	1 Months Ended		3 Months Ended	12 Months Ended
	May 31, 2013	Jul. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jun. 30, 2012
Summary of Accounting Policies [Line Items]
Allowance for Funds Used During Construction, Capitalized Interest				$ 1	$ 2	$ 1
Minimum Ownership Interest Percentage For Investments Recorded Using Entity Method				20.00%
Maximum Ownership Interest Percentage For Investments Recorded Using Entity Method				50.00%
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		$ 0	136	0
Acquisition		$ 24			24
Amount of removal costs recognized as a component of depreciation expense recorded as a regulatory liability			$ 593	593	573
Allowance for doubtful accounts			25	25	23
Provision for doubtful accounts				20	15	25
Write-downs of natural gas inventory to lower of cost or market			4	4	4	$ 11
Materials and supplies			34	34	83
Natural gas			145	145	145
Total inventory			179	179	228
Margin deposits			4	4	12
Under Recovered Gas Costs			22	22	86
Over Recovered Gas Costs			$ 42	$ 42	$ 6
Waskom Gas Processing Company [Member]
Summary of Accounting Policies [Line Items]
Equity Method Investment, Ownership Percentage							50.00%
Percentage of Ownership in Affiliate 2 Acquired		50.00%
Business Acquisition, Purchase Price Allocation, Remaining Interest		$ 201
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage							50.00%
Waskom Gas Processing Company [Member]
Summary of Accounting Policies [Line Items]
Acquisition		17
Gathering and Related Assets [Member]
Summary of Accounting Policies [Line Items]
Acquisition		$ 7
Enogex LLC [Member] \| OGE ARCLIGHT [Member]
Summary of Accounting Policies [Line Items]
Equity Interest Contributed, Percentage	100.00%
Southeast Supply Header Llc [Member]
Summary of Accounting Policies [Line Items]
Equity Interest Contributed, Percentage	24.95%
Enable Midstream Partners [Member]
Summary of Accounting Policies [Line Items]
Equity Method Investment, Ownership Percentage			58.30%	58.30%
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest				50.00%
Incentive Distribution Right			40.00%
Enable Midstream Partners [Member] \| OGE [Member]
Summary of Accounting Policies [Line Items]
Equity Method Investment, Ownership Percentage			28.50%	28.50%
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest				50.00%
Incentive Distribution Right			60.00%
Enable Midstream Partners [Member] \| ArcLight [Member]
Summary of Accounting Policies [Line Items]
Equity Method Investment, Ownership Percentage			13.20%	13.20%

Property, Plant and Equipment (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment, Gross

$ 4,815

$ 9,615

Accumulated depreciation and amortization

1,379

1,714

Property, Plant and Equipment, Net

3,436

7,901

Depreciation expense

218

267

$ 244

Amortization expense

Total depreciation and amortization expense

230

285

262

Beginning balance

135

132

Accretion expense

Revisions in estimates of cash flows

(38)

(3)

Ending balance

101

135

$ 132

Increase (Decrease) in ARO from the revision of estimate

$ (38)

(3)

Natural Gas Distribution [Member]

Property, Plant and Equipment [Line Items]

Weighted Average Useful Lives (in years)

Property, Plant and Equipment, Gross

$ 4,694

4,321

Accumulated depreciation and amortization

$ 1,324

1,194

Energy Services [Member]

Property, Plant and Equipment [Line Items]

Weighted Average Useful Lives (in years)

Property, Plant and Equipment, Gross

$ 82

Accumulated depreciation and amortization

$ 28

Interstate Pipelines [Member]

Property, Plant and Equipment [Line Items]

Weighted Average Useful Lives (in years)

Property, Plant and Equipment, Gross

$ 0

^[1]

2,803

Accumulated depreciation and amortization

$ 0

355

Field Services [Member]

Property, Plant and Equipment [Line Items]

Weighted Average Useful Lives (in years)

Property, Plant and Equipment, Gross

$ 0

^[1]

2,359

Accumulated depreciation and amortization

$ 0

118

Other property [Member]

Property, Plant and Equipment [Line Items]

Weighted Average Useful Lives (in years)

Property, Plant and Equipment, Gross

$ 39

Accumulated depreciation and amortization

$ 27

$ 22

[1]	Following the formation of Enable on May 1, 2013, substantially all of the assets of CERC's former Interstate Pipelines and Field Services business segments are owned by Enable.

Goodwill (Details) - USD ($)
$ in Millions

1 Months Ended

12 Months Ended

Jul. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Goodwill [Line Items]

Goodwill

$ 840

$ 1,468

$ 1,696

Impairment Charge

252

Acquisition

$ 24

Contributed to Enable

^[1]

628

Natural Gas Distribution [Member]

Goodwill [Line Items]

Goodwill

746

Impairment Charge

Acquisition

Contributed to Enable

^[1]

Interstate Pipelines [Member]

Goodwill [Line Items]

Goodwill

579

Impairment Charge

Acquisition

Contributed to Enable

^[1]

579

Energy Services [Member]

Goodwill [Line Items]

Goodwill

335

Impairment Charge

252

Acquisition

Contributed to Enable

^[1]

Field Services [Member]

Goodwill [Line Items]

Goodwill

Impairment Charge

Acquisition

Contributed to Enable

^[1]

Corporate and Other [Member]

Goodwill [Line Items]

Goodwill

$ 11

Impairment Charge

Acquisition

$ 0

Contributed to Enable

^[1]

$ 0

[1]	See Note 2(b).

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

Dec. 31, 2013

Dec. 31, 2012

Schedule Of Regulatory Assets And Liabilities [Line Items]

Regulatory liabilities

$ (642)

$ (619)

Net Regulatory Assets (Liabilities)

(542)

(514)

Other Longterm Regulatory Assets Member

Schedule Of Regulatory Assets And Liabilities [Line Items]

Regulatory assets in other long-term assets (1)

^[1]

$ 100

$ 105

[1]	Regulatory assets that are not earning a return were not material at December 31, 2013 or 2012.

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

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Pension and Savings Plan

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

5.00%

Pension Expense

$ 29

$ 32

$ 30

Non Qualified Pension Plan Benefit Expense

$ 2

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

$ 19

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

$ 8

$ 10

$ 9

Assumptions used to determine net postretirement benefit costs

Discount rate

3.90%

4.80%

5.20%

Expected return on plan assets

3.10%

4.50%

Change in Plan Assets [Roll Forward]

Plan assets, beginning of year

$ 24

Plan assets, end of year

$ 24

Amounts Recognized in Balance Sheets

Other liabilities-benefit obligations

$ (102)

(122)

Actuarial Assumptions

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

5.50%

Annualized individual discount rates based on time period, minimum

6 months

Annualized individual discount rates based on time period, maximum

99 years

Amounts reclassified from accumulated other comprehensive income: [Abstract]

Net current period other comprehensive income

$ 6

$ (2)

Amounts recognized in accumulated other comprehensive loss

Unrecognized actuarial loss

Unrecognized prior service cost

Total recognized in accumulated other comprehensive loss

Less: deferred tax benefit (1)

^[1]

(15)

(21)

Net amount recognized in accumulated other comprehensive (income) loss

(5)

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

Net gain

Amortization of prior service cost

Total recognized in other comprehensive income

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

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

Other Pension Plan, Postretirement or Supplemental Plans, Defined Benefit [Member]

Amounts reclassified from accumulated other comprehensive income: [Abstract]

Beginning Balance

(1)

Other comprehensive income before reclassifications (1)

^[2]

Prior service cost (2)

^[3]

Actuarial gains (2)

^[3]

Total reclassifications from accumulated other comprehensive income

Tax expense

(6)

Net current period other comprehensive income

Ending Balance

(1)

Other Postretirement Benefit Plans, Defined Benefit [Member]

Change in Benefit Obligation [Roll Forward]

Accumulated benefit obligation, beginning of year

133

118

Service cost

Interest cost

Benefits paid

(13)

Participant contributions

Medicare reimbursement

Actuarial (gain) loss

(16)

Accumulated benefit obligation, end of year

116

133

118

Change in Plan Assets [Roll Forward]

Plan assets, beginning of year

Benefits paid

(13)

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

(83)

(102)

Net liability, end of year

$ (90)

$ (109)

Actuarial Assumptions

Discount rate

4.75%

3.90%

Expected long-term return on assets

3.10%

Prescription cost trend rate assumed for the next year

7.00%

9.00%

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

2018

2017

Year that the prescription drug rate reaches the ultimate trend rate

2018

2017

Age Pre 65 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

Actuarial Assumptions

Healthcare cost trend rate assumed for the next year

7.00%

9.00%

Age Post 65 [Member] [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

Actuarial Assumptions

Healthcare cost trend rate assumed for the next year

7.50%

9.00%

[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.
[2]	Total other comprehensive income related to the re-measurement of pension, postretirement and other postemployment plans.
[3]	These accumulated other comprehensive components are included in the computation of net periodic cost.

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

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

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

Fair Value of Plan Assets

$ 26

$ 24

Percentage of investment in mutual funds allocated to fixed income securities

73.00%

70.00%

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

20.00%

23.00%

Percentage of investment in mutual funds allocated to international equities

7.00%

Estimated contributions next fiscal year

$ 7

Postemployment Benefits

Postemployment benefit income (expense)

$ 5

$ 4

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

$ 24

$ 22

Expected Future Benefit Payments, Fiscal Year Maturity

Benefit Payments - 2014

Benefit Payments - 2015

Benefit Payments - 2016

Benefit Payments - 2017

Benefit Payments - 2018

Benefit Payments - 2019-2023

Medicare Subsidy Receipts - 2014

(2)

Medicare Subsidy Receipts - 2015

(2)

Medicare Subsidy Receipts - 2016

(2)

Medicare Subsidy Receipts - 2017

(2)

Medicare Subsidy Receipts - 2018

(3)

Medicare Subsidy Receipts - 2019-2023

$ (17)

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]	73% of the amount invested in mutual funds was in fixed income securities; 20% was in U.S. equities and 7% was in international equities.
[2]	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.

Employee Benefit Plans Other Employee Matters (Details)	12 Months Ended
Employee Benefit Plans Other Employee Matters (Details)	Dec. 31, 2013
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, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]
Money Pool Borrowings	$ 38	$ 779
Money Pool Borrowings Weighted-Average Interest Rate	0.03%
Net interest expense related to affiliate borrowings	$ 2	4	$ 1
Corporate services charge	117	163	164
Dividends paid to parent	$ 0	$ 0	$ 0

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

12 Months Ended

Dec. 31, 2013

USD ($)

Years

MMcf

Dec. 31, 2012

USD ($)

MMcf

Dec. 31, 2011

USD ($)

Weather Hedges Term | Years

Derivative, Gain (Loss) on Derivative, Net

$ (16)

$ 8

$ (1)

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

607

489

Net long position (in MMcf) | MMcf

101

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

Derivative Instruments, Assets, Physical Forwards Purchased

$ 1

Collateral Netting

$ 9

Total non-trading derivative assets and liabilities net of collateral

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

Derivative Assets Investment Grade Non Trading

^[1]

Derivative Assets Non Trading

Natural gas derivatives [Member]

Derivative, Fair Value, Net

^[2]

Derivative, fair value, offsets, net

Total non-trading derivative assets and liabilities net of collateral

^[3]

Current Assets [Member] | Natural gas derivatives [Member]

Derivative Assets Fair Value

^[2]

Natural gas derivatives (2)

(8)

(6)

Total non-trading derivative assets and liabilities net of collateral

^[3]

Other Assets [Member] | Natural gas derivatives [Member]

Derivative Assets Fair Value

^[2]

Natural gas derivatives (2)

(1)

Total non-trading derivative assets and liabilities net of collateral

^[3]

Current Liabilities [Member] | Natural gas derivatives [Member]

Derivative Liabilities Fair Value

^[2]

(25)

(28)

Derivative Liability, Fair Value, Gross Asset

Total non-trading derivative assets and liabilities net of collateral

^[3]

(17)

(14)

Other Liabilities [Member] | Natural gas derivatives [Member]

Derivative Liabilities Fair Value

^[2]

(5)

(4)

Derivative Liability, Fair Value, Gross Asset

Total non-trading derivative assets and liabilities net of collateral

^[3]

(4)

(2)

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

^[4],[5]

(63)

(144)

Derivative Instruments Physical Forwards Purchased

(2)

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],[6]

Derivative Assets Non Trading

^[6]

Not Designated as Hedging Instrument [Member]

Derivative Assets Fair Value

Derivative Liabilities Fair Value

(30)

(32)

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

Derivative Assets Fair Value

^[7],[8],[9]

^[10],[11]

Derivative Liabilities Fair Value

(4)

^[7],[8],[9]

(1)

^[10],[11]

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

Derivative Assets Fair Value

^[7],[9]

^[10],[11]

Derivative Liabilities Fair Value

^[7],[9]

^[10],[11]

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

Derivative Assets Fair Value

^[7],[9]

^[10],[11]

Derivative Liabilities Fair Value

(21)

^[7],[9]

(27)

^[10],[11]

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

Derivative Assets Fair Value

^[7],[9]

^[10],[11]

Derivative Liabilities Fair Value

$ (5)

^[7],[9]

$ (4)

^[10],[11]

[1]	“Investment grade” is primarily determined using publicly available credit ratings and considering credit support (such as parent company guarantees) 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]	Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.
[3]	The derivative assets and liabilities on the Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.
[4]	The Gains (Losses) in Expense: Natural Gas includes $(2) million during the year ended December 31, 2013 related to physical forwards purchased from Enable.
[5]	The Gains (Losses) in Expense: Natural Gas includes $-0-, $(38) million and $(107) million of costs in 2013, 2012 and 2011, respectively, associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered through purchased gas adjustments.
[6]	Retail end users represent customers who have contracted to fix the price of a portion of their physical gas requirements for future periods.
[7]	Natural gas contracts are presented on a net basis in the Consolidated Balance Sheets. Natural gas contracts are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Consolidated Balance Sheets. The net of total non-trading derivative assets and liabilities was a $13 million asset as shown on CERC’s Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above offset by collateral netting of less than $1 million.
[8]	The $28 million Derivative Current Asset includes $1 million related to physical forwards purchased from Enable.
[9]	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 607 Bcf or a net 46 Bcf long position. Of the net long position, basis swaps constitute 99 Bcf.
[10]	Natural gas contracts are presented on a net basis in the Consolidated Balance Sheets. Natural gas contracts are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Consolidated Balance Sheets. The net of total non-trading derivative assets and liabilities was a $26 million asset as shown on CERC’s Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above offset by collateral netting of $9 million.
[11]	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 489 billion cubic feet (Bcf) or a net 101 Bcf long position. Of the net long position, basis swaps constitute 73 Bcf.

Fair Value Measurements (Details) - USD ($)

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Assets

Corporate equities

$ 2,000,000

$ 1,000,000

Investments, including money market funds

11,000,000

Natural gas derivatives (2)

34,000,000

^[1]

42,000,000

Total assets

47,000,000

54,000,000

Liabilities

Natural gas derivatives

21,000,000

16,000,000

Total liabilities

21,000,000

16,000,000

Cash collateral posted with counterparties

1,000,000

9,000,000

Derivative Instruments, Assets, Physical Forwards Purchased

1,000,000

Carrying Amount [Member]

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

Notes receivable - affiliated companies

363,000,000

Long-term debt

2,240,000,000

2,641,000,000

Fair Value [Member]

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

Notes receivable - affiliated companies

363,000,000

Long-term debt

2,466,000,000

3,094,000,000

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

2,000,000

^[2]

6,000,000

^[2]

$ 3,000,000

Total gains (1)

^[3]

3,000,000

6,000,000

Total settlements (1)

^[3]

(3,000,000)

(6,000,000)

(3,000,000)

Total purchases

2,000,000

Transfers out of Level 3

(1,000,000)

(2,000,000)

Transfers into Level 3

1,000,000

Ending balance (2)

^[2]

3,000,000

2,000,000

6,000,000

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

2,000,000

1,000,000

$ 5,000,000

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

Assets

Corporate equities

2,000,000

1,000,000

Investments, including money market funds

11,000,000

Natural gas derivatives (2)

5,000,000

^[1]

1,000,000

Total assets

18,000,000

13,000,000

Liabilities

Natural gas derivatives

1,000,000

5,000,000

Total liabilities

1,000,000

5,000,000

Significant Other Observable Inputs (Level 2) [Member]

Assets

Corporate equities

Investments, including money market funds

Natural gas derivatives (2)

33,000,000

^[1]

40,000,000

Total assets

33,000,000

40,000,000

Liabilities

Natural gas derivatives

27,000,000

21,000,000

Total liabilities

27,000,000

21,000,000

Significant Unobservable Inputs (Level 3) [Member]

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

Illiquid forward price low range

3.79

Illiquid forward price high range

$ 4.94

Option volatilities low range

0.00%

Option volatilities high range

53.00%

Assets

Corporate equities

$ 0

Investments, including money market funds

Natural gas derivatives (2)

5,000,000

^[1]

7,000,000

Total assets

5,000,000

7,000,000

Liabilities

Natural gas derivatives

2,000,000

5,000,000

Total liabilities

2,000,000

5,000,000

Netting Adjustments [Member]

Assets

Corporate equities

^[4]

^[5]

Investments, including money market funds

^[4]

^[5]

Natural gas derivatives (2)

(9,000,000)

^[1],[4]

(6,000,000)

^[5]

Liabilities

Natural gas derivatives

$ (9,000,000)

^[4]

$ (15,000,000)

^[5]

[1]	The (Level 2) Natural gas derivative assets of $33 million include $1 million related to physical forwards purchased from Enable.
[2]	During 2013, 2012 and 2011, CERC did not have significant Level 3 sales.
[3]	During 2013, 2012 and 2011, CERC did not have Level 3 unrealized gains (losses) or settlements related to price stabilization activities of the Natural Gas Distribution business segment.
[4]	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 less than $1 million posted with the same counterparties.
[5]	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.

Unconsolidated Affiliates (Details) - USD ($)
$ in Millions

3 Months Ended

4 Months Ended

8 Months Ended

12 Months Ended

Dec. 31, 2013

Apr. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

May 01, 2013

Contributed Assets

$ 5,800

Contributed Assets, Plant, Property and Equipments

4,700

Goodwill, Transfers

$ 629

Contributed Liabilities

1,500

Investment in unconsolidated affiliates

$ 4,518

$ 405

Guarantor Obligations, Current Amount

1,050

Transitional Service Costs to be Reimbursed

119

Transitional Service Costs Receivable

Term Loan of Affiliate

1,050

Cost of natural gas purchases, affiliates

123

Due to Affiliate

Equity in earnings of unconsolidated affiliates

188

$ 30

CERC's approximate 58.3% interest

173

Basis difference accretion gain

CERC's approximate 58.3% interest, net

173

Noncontrolling interest

Enable Partners' Capital

8,148

CERC's approximate 58.3% interest

4,753

CERC's basis difference

(434)

CERC's investment in Enable

4,319

Basis difference attributable to goodwill as of May 1, 2013 (1)

^[1]

229

Basis difference to be accreted over 30 years as of May 1, 2013

210

Total basis difference as of May 1, 2013

439

Accumulated accretion of basis difference as of December 31, 2013

(5)

CERC's basis difference in Enable as of December 31, 2013

434

Midstream Partnership [Member]

Debt repayment by affiliate

1,050

Debt of Affiliate

363

Investment in unconsolidated affiliates

4,319

4,300

Guarantor Obligations, Current Amount

1,050

Interest and Other Income

Current assets

549

Non-current assets

10,683

Current liabilities

720

Non-current liabilities

2,331

Other Entity [Member]

Investment in unconsolidated affiliates

$ 0

SESH [Member]

Equity Method Investment, Ownership Percentage

25.05%

Contributed Assets

$ 197

Equity Method Investment, Additional Contribution of Ownership Percentage

24.95%

Investment in unconsolidated affiliates

^[2]

$ 199

404

Equity Method Investment, Contributed Ownership Percentage

24.95%

Other Entity [Member]

Equity in earnings of unconsolidated affiliates

^[3]

SESH [Member]

Equity in earnings of unconsolidated affiliates

^[2]

$ 8

^[2]

Proceeds from Equity Method Investment, Dividends or Distributions

Midstream Partnership [Member]

Equity in earnings of unconsolidated affiliates

173

$ 0

Operating revenues

2,123

Cost of sales, excluding depreciation and amortization

1,241

Operating income

322

Net income attributable to Enable

289

CERC's approximate 58.3% interest

168

CERC's approximate 58.3% interest, net

168

Proceeds from Equity Method Investment, Dividends or Distributions

$ 106

Enable Midstream Partners [Member]

Equity Method Investment, Ownership Percentage

58.30%

Senior Subordinated Notes [Member]

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

2.10%

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

2.45%

[1]	This difference related to CERC’s proportionate share of Enable’s goodwill arising from its acquisition of Enogex, and therefore will not be recognized by CERC.
[2]	On May 1, 2013, CERC contributed a 24.95% interest in SESH to Enable, leaving CERC with a 25.05% interest in SESH.
[3]	On July 31, 2012, Waskom became a wholly owned subsidiary of CenterPoint Energy. Beginning on August 1, 2012, Waskom’s operating results are consolidated on the Statements of Consolidated Income. On May 1, 2013, CenterPoint Energy contributed Waskom to Enable.

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

3 Months Ended

12 Months Ended

Jun. 30, 2013

Dec. 31, 2013

May 01, 2013

Apr. 30, 2013

Dec. 31, 2012

Debt Instrument [Line Items]

Short-term Debt

^[1]

$ 43

$ 38

Long-term Debt

Long-term Debt, Excluding Current Maturities

2,240

2,276

Long-term Debt, Current Maturities

^[1]

365

Short Term Borrowings And Current Portion Long Term Debt

^[1]

403

Long-term Debt, Maturities in 2014

Long-term Debt, Maturities in 2015

Long-term Debt, Maturities in 2016

325

Long-term Debt, Maturities in 2017

250

Long-term Debt, Maturities in 2018

418

Inventory financing [Member]

Debt Instrument [Line Items]

Short-term Debt

^[1]

Long-term Debt

Midstream Partnership [Member]

Debt Instrument [Line Items]

Debt repayment by affiliate

$ 1,050

Line of Credit [Member]

Debt Instrument [Line Items]

Size of Facility

600

950

Loans

Letters of Credit

Commercial Paper

$ 118

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 2016 to 2041 [Member]

Debt Instrument [Line Items]

Long-term Debt, Excluding Current Maturities

$ 2,168

2,328

Long-term Debt, Current Maturities

^[1]

$ 0

365

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

4.50%

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

6.625%

Commercial Paper [Member]

Debt Instrument [Line Items]

Long-term Debt, Excluding Current Maturities

^[2]

$ 118

Long-term Debt, Current Maturities

^[1],[2]

Unamortized Discount Premium Member

Debt Instrument [Line Items]

Long-term Debt, Excluding Current Maturities

(46)

(52)

Long-term Debt, Current Maturities

^[1]

$ 0

April 2013 [Member] | Senior Notes [Member]

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 365

Debt Instrument, Interest Rate, Stated Percentage

7.875%

May 2013 [Member] | Midstream Partnership [Member]

Debt Instrument [Line Items]

Debt repayment by affiliate

$ 1,050

May 2013 [Member] | Senior Notes [Member]

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 160

Debt Instrument, Interest Rate, Stated Percentage

5.95%

Extinguishment Of Debt Purchase Price Percentage Of Principal

103.419%

May 2013 [Member] | Commercial Paper [Member]

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 357

[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	12 Months Ended
Income Taxes (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Unrecognized tax expense, increase resulting from prior period tax positions	$ (2.0)	$ 0.0	$ (1.0)
Unrecognized tax expense		(20.0)
Current income tax expense:
Federal	5.0	0.0	34.0
State	9.0	1.0	9.0
Total current expense	14.0	1.0	43.0
Deferred income tax expense:
Federal	350.0	198.0	140.0
State	7.0	47.0	4.0
Total deferred expense	357.0	245.0	144.0
Total income tax expense	371.0	246.0	187.0
Income tax reconciliation
Income before income taxes	$ 435.0	$ 383.0	$ 503.0
Federal statutory income tax rate	35.00%	35.00%	35.00%
Expected federal income tax expense	$ 152.0	$ 134.0	$ 176.0
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	23.0	31.0	9.0
Increase (decrease) in settled and uncertain income tax positions	(2.0)	(7.0)	1.0
Increase (decrease) in tax expense due to formation of midstream partnership	198.0	0.0	0.0
Goodwill impairment	0.0	88.0	0.0
Other, net	0.0	0.0	1.0
Total	219.0	112.0	11.0
Total income tax expense	$ 371.0	$ 246.0	$ 187.0
Effective tax rate	85.30%	64.20%	37.20%
Deferred Tax Liabilities, Goodwill and Intangible Assets	$ 225.0
Tax Adjustments, Settlements, and Unusual Provisions	(2.0)	$ 7.0
Goodwill impairment	0.0	252.0	$ 0.0
Amount of net reduction to income tax expense from state income tax expense, net of federal income tax		20.0
Deferred Tax Assets [Abstract]
Allowance for doubtful accounts	10.0	9.0
Deferred gas costs	7.0	0.0
Other, current deferred tax assets	7.0	0.0
Total current deferred tax assets	24.0	9.0
Employee benefits	41.0	49.0
Loss and credit carryforwards	193.0	192.0
Regulatory liabilities, net	0.0	196.0
Other, noncurrent deferred tax assets	59.0	51.0
Total non-current deferred tax assets before valuation allowance	293.0	488.0
Valuation allowance	(2.0)	(2.0)
Total non-current deferred tax assets, net of valuation allowance	291.0	486.0
Total deferred tax assets, net of valuation allowance	315.0	495.0
Deferred Tax Liabilities [Abstract]
Deferred gas costs	0.0	25.0
Other	3.0	5.0
Total current deferred tax liabilities	3.0	30.0
Depreciation	746.0	2,033.0
Regulatory assets, net	17.0	0.0
Investment in unconsolidated affiliates	1,590.0	0.0
Other, non-current deferred tax liabilities	20.0	129.0
Total non-current deferred tax liabilities	2,373.0	2,162.0
Total deferred tax liabilities	2,376.0	2,192.0
Accumulated deferred income taxes, net	2,061.0	1,697.0
Reconciliation of Unrecognized Tax Benefits (Expenses) [Roll Forward]
Balance, beginning of year		8.0	11.0
Tax Positions related to prior years:
Reductions	0.0	(27.0)	(3.0)
Tax Positions related to current year:
Additions	0.0	0.0	1.0
Unrecognized Tax Benefits, Increase Resulting from Settlements with Taxing Authorities	22.0		0.0
Settlements		(1.0)
Balance, end of year	0.0		8.0
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	0.0	0.0	6.0
Interest expense on uncertain income tax positions	4.0	(3.0)	$ (0.4)
Accrued interest receivable on uncertain income tax positions	11.0	$ 7.0
Federal [Member]
Deferred Tax Liabilities [Abstract]
Federal net operating loss carryforwards to expire in 2030	$ 495.0
Operating Loss Carryforwards, Expiration Dates	Dec. 31, 2031
State [Member]
Deferred Tax Liabilities [Abstract]
Federal net operating loss carryforwards to expire in 2030	$ 387.0
Deferred Tax Assets, Capital Loss Carryforwards	$ 244.0
Other Tax Carryforward, Expiration Dates	Dec. 31, 2017
State capital loss carryforwards, full valuation allowance	$ 3.0
State capital loss carryforwards, valuation allowance net of federal tax	2.0
Enable Midstream Partners [Member]
Deferred income tax expense:
Total deferred expense	$ (27.0)

Commitments and Contingencies (Details)	12 Months Ended
Commitments and Contingencies (Details)	Dec. 31, 2013 USD ($) Years	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	May 01, 2013 USD ($)
Operating Leases, Future Minimum Payments Due [Abstract]
2014	$ 6,000,000
2015	4,000,000
2016	3,000,000
2017	2,000,000
2018	2,000,000
2019 and beyond	3,000,000
Total	20,000,000
Total lease expense for all operating leases	$ 20,000,000	$ 26,000,000	$ 42,000,000
Commitments and Contingencies Disclosure [Abstract]
Loss Contingency, Damages Sought	in excess of $1 billion
Loss Contingency Total Gas Market Manipulation Cases	30
Loss Contingency Pending Gas Market Manipulation Lawsuits Number	1
Site Contingency Completed Remediation	2
Site Contingency Remaining Minnesota Sites	5
Site Contingency Sites Without Liability	2
Accrual for Environmental Loss Contingencies	$ 14,000,000
Site Contingency Loss Exposure Low Estimate	6,000,000
Site Contingency Loss Exposure High Estimate	$ 41,000,000
Site Contingency Estimated Time Frame To Resolve Contingency Low Estimate \| Years	30
Site Contingency Estimated Time Frame To Resolve Contingency High Estimate \| Years	50
Environmental Costs Recognized, Recovery Credited to Expense	$ 285,000
Recorded Third-Party Environmental Recoveries, Amount	6,300,000
Guarantor Obligations, Maximum Exposure, Undiscounted	58,000,000
Guarantor Obligations, Current Amount				$ 1,050,000,000
Natural Gas supply commitments [Member]
Recorded Unconditional Purchase Obligation [Line Items]
2014	408,000,000
2015	391,000,000
2016	310,000,000
2017	250,000,000
2018	244,000,000
After 2018	$ 120,000,000

Unaudited Quarterly Information (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

^[1]

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

^[2]

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Revenue from External Customers

$ 1,543

$ 891

$ 1,235

$ 1,853

$ 1,551

$ 954

$ 846

$ 1,550

$ 5,522

$ 4,901

$ 6,102

Operating Income (Loss)

250

211

(152)

106

229

401

394

662

Net Income (Loss)

$ 66

$ 32

$ (162)

$ 128

$ 104

$ (127)

$ 42

$ 118

$ 64

$ 137

$ 316

[1]	Effective May 1, 2013, CERC Corp. contributed CenterPoint Midstream to Enable. See Note 2(b) and Note 10 for further discussion on the formation of Enable and CERC’s investment in Enable, respectively.
[2]	See Note 2(b) and Note (4) for further discussion on the acquisition of additional interest in Waskom and the goodwill impairment charge, respectively.

- 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

1 Months Ended

3 Months Ended

4 Months Ended

8 Months Ended

12 Months Ended

Jul. 31, 2012

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

^[1]

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

^[2]

Jun. 30, 2012

Mar. 31, 2012

Apr. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

May 01, 2013

Segment Reporting Information [Line Items]

Revenue from External Customers

$ 1,543

$ 891

$ 1,235

$ 1,853

$ 1,551

$ 954

$ 846

$ 1,550

$ 5,522

$ 4,901

$ 6,102

Depreciation and Amortization

230

285

262

Operating Income (Loss)

250

211

(152)

106

229

401

394

662

Total Assets

10,542

11,190

$ 10,542

10,542

11,190

10,687

Capital Expenditures for Long-Lived Assets

478

549

599

Equity income

188

Investment in unconsolidated affiliates

4,518

405

4,518

405

Retail gas sales

4,150

3,328

4,019

Wholesale gas sales

913

613

1,149

Gas transportation and processing

345

847

824

Energy products and services

114

113

110

Total

1,543

$ 891

$ 1,235

$ 1,853

1,551

$ 954

$ 846

$ 1,550

5,522

4,901

6,102

Natural Gas Distribution [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

2,837

2,320

2,823

Depreciation and Amortization

185

173

166

Operating Income (Loss)

263

226

Total Assets

4,976

4,775

4,976

4,775

4,636

Capital Expenditures for Long-Lived Assets

430

359

295

Total

2,837

2,320

2,823

Energy Services [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

2,374

1,758

2,488

Depreciation and Amortization

Operating Income (Loss)

(250)

Total Assets

895

839

895

839

1,089

Capital Expenditures for Long-Lived Assets

Total

2,374

1,758

2,488

Interstate Pipelines [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

^[3]

133

^[4]

356

421

Depreciation and Amortization

^[3]

^[4]

Operating Income (Loss)

^[3]

^[4]

207

248

Total Assets

^[3]

$ 0

^[4]

4,004

$ 0

^[4]

4,004

3,867

Capital Expenditures for Long-Lived Assets

^[3]

^[4]

132

Equity income

$ 7

Interest in jointly-owned asset (in hundredths)

50.00%

Investment in unconsolidated affiliate

404

409

Total

^[3]

$ 133

^[4]

356

421

Field Services [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

^[5]

178

^[4]

467

370

Depreciation and Amortization

^[5]

^[4]

Operating Income (Loss)

^[5]

^[4]

214

189

Total Assets

^[5]

$ 0

^[4]

2,453

$ 0

^[4]

2,453

1,894

Capital Expenditures for Long-Lived Assets

^[5]

$ 16

^[4]

201

Equity income

Interest in jointly-owned asset (in hundredths)

50.00%

Investment in unconsolidated affiliate

Total

^[5]

$ 178

^[4]

467

370

Midstream Investments [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

^[6]

Depreciation and Amortization

^[6]

Operating Income (Loss)

^[6]

Total Assets

^[6]

$ 4,518

4,518

Capital Expenditures for Long-Lived Assets

^[6]

Total

^[6]

Corporate and Other [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

Depreciation and Amortization

Operating Income (Loss)

(20)

(3)

(7)

Total Assets

$ 1,149

647

$ 1,149

1,149

647

660

Capital Expenditures for Long-Lived Assets

Total

Intersegment Eliminations [Member]

Segment Reporting Information [Line Items]

Capital Expenditures for Long-Lived Assets

$ 0

Waskom Gas Processing Company [Member]

Segment Reporting Information [Line Items]

Interest in jointly-owned asset (in hundredths)

50.00%

Percentage of Ownership in Affiliate 2 Acquired

50.00%

SESH [Member]

Segment Reporting Information [Line Items]

Interest in jointly-owned asset (in hundredths)

25.05%

Investment in unconsolidated affiliates

^[7]

$ 199

404

$ 199

404

Midstream Partnership [Member]

Segment Reporting Information [Line Items]

Investment in unconsolidated affiliates

4,319

$ 4,300

Consolidation, Eliminations [Member]

Segment Reporting Information [Line Items]

Total Assets

$ (996)

$ (1,528)

(996)

(1,528)

(1,459)

Intersegment Eliminations [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

(124)

(233)

(215)

Total

(124)

(233)

(215)

Intersegment Eliminations [Member] | Natural Gas Distribution [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

(26)

(22)

(18)

Total

(26)

(22)

(18)

Intersegment Eliminations [Member] | Energy Services [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

(27)

(26)

(23)

Total

(27)

(26)

(23)

Intersegment Eliminations [Member] | Interstate Pipelines [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

^[3]

(53)

^[4]

(146)

(132)

Total

^[3]

(53)

^[4]

(146)

(132)

Intersegment Eliminations [Member] | Field Services [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

^[5]

(18)

^[4]

(39)

(42)

Total

^[5]

(18)

^[4]

(39)

(42)

Intersegment Eliminations [Member] | Midstream Investments [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

^[6]

Total

^[6]

Intersegment Eliminations [Member] | Corporate and Other [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

Total

Midstream Partnership [Member]

Segment Reporting Information [Line Items]

Equity income

173

SESH [Member]

Segment Reporting Information [Line Items]

Equity income

$ 15

^[7]

$ 8

$ 26

^[7]

$ 21

^[7]

Midstream Investments [Member] | Waskom [Member]

Segment Reporting Information [Line Items]

Equity Interest Contributed, Percentage

100.00%

[1]	Effective May 1, 2013, CERC Corp. contributed CenterPoint Midstream to Enable. See Note 2(b) and Note 10 for further discussion on the formation of Enable and CERC’s investment in Enable, respectively.
[2]	See Note 2(b) and Note (4) for further discussion on the acquisition of additional interest in Waskom and the goodwill impairment charge, respectively.
[3]	Interstate Pipelines recorded equity income of $7 million, $26 million and $21 million in the years ended December 31, 2013, 2012 and 2011, respectively, from its 50% interest in SESH, a jointly-owned pipeline. These amounts are included in Equity in earnings of unconsolidated affiliates under the Other Income (Expense) caption. Interstate Pipelines’ investment in SESH was $404 million and $409 million as of December 31, 2012 and 2011, respectively, and is included in Investment in unconsolidated affiliates. As discussed above, effective May 1, 2013, CenterPoint Energy reports equity earnings associated with its interest in Enable and equity earnings associated with its retained interest in SESH under a new Midstream Investments segment, and no longer has an Interstate Pipelines reporting segment prospectively.
[4]	Results reflected in the year ended December 31, 2013 represent only January 2013 through April 2013.
[5]	Field Services recorded equity income of $5 million and $9 million for the years ended December 31, 2012 and 2011, respectively, from its 50% interest in a jointly-owned gas processing plant. These amounts are included in Equity in earnings of unconsolidated affiliates under the Other Income (Expense) caption. Field Services’ investment in the jointly-owned gas processing plant was $63 million as of December 31, 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 CenterPoint Energy did not already own. CERC contributed 100% interest in Waskom to Enable on May 1, 2013. Effective May 1, 2013, CERC equity earnings associated with its interest in Enable under a new Midstream Investments segment, and no longer has a Field Services reporting segment prospectively.
[6]	Midstream Investments reported equity earnings of $173 million from Enable and $8 million of equity earnings from CERC’s retained interest in SESH for the eight months ended December 31, 2013. Included in total assets of Midstream Investments as of December 31, 2013 is $4,319 million related to CERC’s investment in Enable and $199 million related to CERC’s retained interest in SESH.
[7]	On May 1, 2013, CERC contributed a 24.95% interest in SESH to Enable, leaving CERC with a 25.05% interest in SESH.

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

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Allowance for Trade Receivables [Member]

Valuation and Qualifying Accounts Disclosure [Line Items]

Balance at Beginning of Period

$ 23

$ 24

$ 25

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)

Additions Charged to Other Accounts

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.