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DEI Document - USD ($) $ in Millions	12 Months Ended
DEI Document - USD ($) $ in Millions	Dec. 31, 2014	Feb. 02, 2015	Jun. 30, 2014
Document and Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Entity Registrant Name	Enable Midstream Partners, LP
Entity Central Index Key	0001591763
Entity Filer Category	Non-accelerated Filer
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		214,455,154
Entity Public Float			$ 2,028
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No

Combined and Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues (including revenues from affiliates (Note 13))	$ 3,367	$ 2,489	$ 952
Cost of Goods Sold, excluding depreciation and amortization (including expenses from affiliates (Note 13))	1,914	1,313	129
Operating Expenses:
Operation and maintenance (including expenses from affiliates (Note 13))	527	429	267
Depreciation and amortization	276	212	106
Impairment	8	12	0
Taxes other than income taxes	56	54	34
Total Operating Expenses	867	707	407
Operating Income	586	469	416
Other Income (Expense):
Interest expense (including expenses from affiliates (Note 13))	(70)	(67)	(85)
Equity in earnings of equity method affiliates	20	15	31
Interest income—affiliated companies	0	9	21
Step acquisition gain	0	0	136
Other, net	(1)	0	0
Total Other Income (Expense)	(51)	(43)	103
Income Before Income Taxes	535	426	519
Income tax expense (benefit)	2	(1,192)	203
Net Income	533	1,618	316
Less: Net income attributable to noncontrolling interest	3	3	0
Net Income attributable to Enable Midstream Partners, LP	530	1,615	316
Limited partners' interest in net income attributable to Enable Midstream Partners, LP (Note 4)	$ 530	$ 289	$ 0
Basic and diluted weighted average number of outstanding partner units (Note 4) (in units)	412	390	0
Common Units
Other Income (Expense):
Limited partners' interest in net income attributable to Enable Midstream Partners, LP (Note 4)	$ 339	$ 289	$ 0
Basic and diluted earnings per unit (Note 4) (in dollars per unit)	$ 1.29	$ 0.74	$ 0.00
Basic and diluted weighted average number of outstanding partner units (Note 4) (in units)	264	390	0
Subordinated Units
Other Income (Expense):
Limited partners' interest in net income attributable to Enable Midstream Partners, LP (Note 4)	$ 191	$ 0	$ 0
Basic and diluted earnings per unit (Note 4) (in dollars per unit)	$ 1.28	$ 0.00	$ 0.00
Basic and diluted weighted average number of outstanding partner units (Note 4) (in units)	148	0	0

Combined and Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net income	$ 533	$ 1,618	$ 316
Other comprehensive income	0	0	0
Comprehensive income	533	1,618	316
Less: Comprehensive income attributable to noncontrolling interest	3	3	0
Comprehensive income attributable to Enable Midstream Partners, LP	$ 530	$ 1,615	$ 316

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013
Current Assets:
Cash and cash equivalents	$ 12	$ 108
Accounts receivable	254	306
Accounts receivable—affiliated companies	27	28
Inventory	63	83
Gas imbalances	45	10
Other current assets	37	14
Total current assets	438	549
Property, Plant and Equipment:
Property, plant and equipment	10,464	9,655
Less accumulated depreciation and amortization	882	665
Property, plant and equipment, net	9,582	8,990
Other Assets:
Intangible assets, net	357	383
Goodwill	1,068	1,068
Investment in equity method affiliates	348	198
Other	44	44
Total other assets	1,817	1,693
Total Assets	11,837	11,232
Current Liabilities:
Accounts payable	275	400
Accounts payable—affiliated companies	38	40
Short-term debt	253	204
Taxes accrued	23	20
Gas imbalances	13	13
Other	69	43
Total current liabilities	671	720
Other Liabilities:
Accumulated deferred income taxes, net	9	8
Notes payable—affiliated companies	363	363
Regulatory liabilities	16	16
Other	27	28
Total other liabilities	415	415
Long-Term Debt	1,928	1,916
Commitments and Contingencies (Note 14)
Common units (214,417,908 issued and outstanding at December 31, 2014 and 390,014,360 issued and outstanding at December 31, 2013)	4,353	8,148
Subordinated units (207,855,430 issued and outstanding at December 31, 2014 and 0 issued and outstanding at December 31, 2013, respectively)	4,439	0
Partners’ Capital:
Total partners' capital attributable to Enable Midstream Partners, LP Partners’ Capital	8,792	8,148
Noncontrolling interest	31	33
Total Partners’ Capital	8,823	8,181
Total Liabilities and Partners’ Capital	$ 11,837	$ 11,232

Consolidated Balance Sheets - Parenthetical - shares	Dec. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Common units issued	214,417,908	390,014,360
Common units outstanding	214,417,908	390,014,360
Subordinated units issued	207,855,430	0
Subordinated units outstanding	207,855,430	0

Combined and Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash Flows from Operating Activities:
Net income	$ 533	$ 1,618	$ 316
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	276	212	106
Deferred income taxes	1	(1,194)	196
Impairments	8	12	0
Step acquisition gain	0	0	(136)
Gain on sale/retirement of assets	0	2	0
Equity in earnings of equity method affiliates, net of distributions	3	9	8
Equity based compensation	13	0	0
Amortization of debt costs and discount (premium)	(1)	0	0
Changes in other assets and liabilities:
Accounts receivable, net	52	(81)	(9)
Accounts receivable—affiliated companies	1	(4)	1
Inventory	7	(6)	2
Gas imbalance assets	(35)	2	0
Income taxes receivable	0	19	(1)
Other current assets	17	15	(3)
Other assets	5	(1)	0
Accounts payable	(138)	62	(3)
Accounts payable—affiliated companies	(2)	3	(3)
Gas imbalance liabilities	0	0	(19)
Other current liabilities	29	(2)	(4)
Other liabilities	0	(18)	0
Net cash provided by operating activities	769	648	451
Cash Flows from Investing Activities:
Capital expenditures	(837)	(573)	(202)
Acquisitions, net of cash acquired	0	0	(360)
Proceeds from sale of assets	13	0	0
Decrease (increase) in notes receivable—affiliated companies	0	434	(77)
Return of investment in equity method affiliates	198	0	0
Investment in equity method affiliates	(189)	0	(5)
Other, net	0	(1)	(1)
Net cash provided by (used in) investing activities	(815)	(140)	(645)
Cash Flows from Financing Activities:
Repayment of long term debt	(1,500)	0	0
Proceeds from long term debt, net of issuance costs	1,635	1,046	0
Proceeds from revolving credit facility	122	1,126	0
Repayment of revolving credit facility	(495)	(754)	0
Increase in short-term debt	253	0	0
Decrease of notes payable—affiliated companies	0	(1,542)	194
Repayment of advance with affiliated companies	0	(136)	0
Capital contributions from partners	464	43	0
Distributions to partners	(529)	(183)	0
Net cash provided by (used in) financing activities	(50)	(400)	194
Net Increase in Cash and Cash Equivalents	(96)	108	0
Cash and Cash Equivalents at Beginning of Period	108	0	0
Cash and Cash Equivalents at End of Period	12	108	0
Supplemental Disclosure of Cash Flow Information:
Interest, net of capitalized interest	77	65	85
Income taxes (refunds), net	1	(9)	26
Accounts payable related to capital expenditures	93	43	37
Issuance of common units upon interest acquisition of SESH (Note 9)	161	0	0
Acquisition of Enogex	$ 0	$ 3,788	$ 0

Combined and Consolidated Statements of Enable Midstream Partners, LP Parent Net Equity and Partners' Capital - USD ($) shares in Millions, $ in Millions	Total	Partners' Capital	Parent Net Investment	Accumulated Other Comprehensive Loss	Total Enable Midstream Partners, LP Partners’ Capital	Noncontrolling Interest	Common Units Partners' Capital	Subordinated Units Partners' Capital
Balance, beginning of period at Dec. 31, 2011	$ 2,904	$ 0	$ 2,904	$ (6)	$ 2,898	$ 6
Balance, beginning of period, units at Dec. 31, 2011		0
Changes in Partners' Capital
Net income	316	$ 0	316	0	316	0
Partners' Capital Account, Contributions	1		1	0	1	0
Balance, end of period, units at Dec. 31, 2012		0
Balance, end of period at Dec. 31, 2012	3,221	$ 0	3,221	(6)	3,215	6
Changes in Partners' Capital
Net income	1,326	$ 0	1,326	0	1,326	0
Contributions from (Distributions to) CenterPoint Energy prior to formation (Note 5)	(289)		(295)	6	(289)	0
Balance, end of period, units at Apr. 30, 2013		0
Balance, end of period at Apr. 30, 2013	4,258	$ 0	4,252	0	4,252	6
Balance, beginning of period at Dec. 31, 2012	3,221	$ 0	3,221	(6)	3,215	6
Balance, beginning of period, units at Dec. 31, 2012		0
Changes in Partners' Capital
Net income	1,618
Balance, end of period, units at Dec. 31, 2013							390	0
Balance, end of period at Dec. 31, 2013	8,181		0	0	8,148	33	$ 8,148	$ 0
Balance, beginning of period at Apr. 30, 2013	4,258	$ 0	4,252	0	4,252	6
Balance, beginning of period, units at Apr. 30, 2013		0
Changes in Partners' Capital
Net income	292		0	0	289	3	$ 289
Conversion to a limited partnership, units							227
Conversion to a limited partnership	0		(4,252)	0	0	0	$ 4,252
Issuance of units upon acquisition, units							163
Issuance of units upon acquisition	3,814		0	0	3,788	26	$ 3,788
Distributions to partners	(183)		0	0	(181)	(2)	$ (181)
Balance, end of period, units at Dec. 31, 2013							390	0
Balance, end of period at Dec. 31, 2013	8,181		0	0	8,148	33	$ 8,148	$ 0
Changes in Partners' Capital
Net income	533		0	0	530	3	$ 349	$ 181
Conversion to a limited partnership, units							(208)	208
Conversion to a limited partnership							$ (4,372)	$ 4,372
Issuance of units upon acquisition, units							6
Issuance of units upon acquisition	161		0	0	161	0	$ 161
Issuance of IPO common units, units							25
Issuance of IPO common units	464		0	0	464	0	$ 464
Distributions to partners	(529)	$ (410)	0	0	(524)	(5)		$ (114)
Equity based compensation, units							1
Equity based compensation	13		0	0	13	0	$ 13
Balance, end of period, units at Dec. 31, 2014							214	208
Balance, end of period at Dec. 31, 2014	$ 8,823		$ 0	$ 0	$ 8,792	$ 31	$ 4,353	$ 4,439

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Significant Accounting Policies

Organization

Enable Midstream Partners, LP (Partnership) is a Delaware limited partnership formed on May 1, 2013 by CenterPoint Energy, Inc. (CenterPoint Energy), OGE Energy Corp. (OGE Energy) and affiliates of ArcLight Capital Partners, LLC (ArcLight), pursuant to the terms of the MFA. The Partnership is a large-scale, growth-oriented limited partnership formed to own, operate and develop strategically located natural gas and crude oil infrastructure assets. The Partnership’s assets and operations are organized into two reportable segments: (i) Gathering and Processing, which primarily provides natural gas gathering, processing and fractionation services and crude oil gathering for our producer customers, and (ii) Transportation and Storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to natural gas producers, utilities and industrial customers. The natural gas gathering and processing assets are located in four states and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex basins. This segment also includes a crude oil gathering business in the Bakken Shale formation, principally located in the Williston basin. The natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

The Partnership is controlled equally by CenterPoint Energy and OGE Energy, who each have 50% of the management rights of Enable GP. Enable GP was established by CenterPoint Energy and OGE Energy to govern the Partnership and has no other operating activities. Enable GP is governed by a board made up of an equal number of representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership's Chief Executive Officer and the independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. Based on the 50/50 management ownership, with neither company having control, effective May 1, 2013, CenterPoint Energy and OGE Energy deconsolidated their interests in the Partnership and Enogex, respectively. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP.

At December 31, 2014, CenterPoint Energy held approximately 55.4% of the limited partner interests in the Partnership, or 94,126,366 common units and 139,704,916 subordinated units, and OGE Energy held approximately 26.3% of the limited partner interests in the Partnership, or 42,832,291 common units and 68,150,514 subordinated units. The limited partner interests of the Partnership have limited voting rights on matters affecting the business. As such, limited partners do not have rights to elect the Partnership’s General Partner (Enable GP) on an annual or continuing basis and may not remove Enable GP without at least a 75% vote by all unitholders, including all units held by the Partnership’s limited partners, and Enable GP and its affiliates, voting together as a single class.

Upon conversion to a limited partnership on May 1, 2013, the Partnership’s earnings are generally no longer subject to income tax (other than Texas state margin taxes and taxes associated with the Partnership's corporate subsidiary) and are taxable at the individual partner level. As a result of the conversion to a partnership immediately prior to formation, CenterPoint Energy assumed all outstanding current income tax liabilities and the Partnership derecognized the deferred income tax assets and liabilities by recording an income tax benefit of $1.24 billion. Consequently, the Combined and Consolidated Statements of Income do not include an income tax provision on income earned on or after May 1, 2013 (other than Texas state margin taxes and taxes associated with the Partnership's corporate subsidiary). See Note 15 for further discussion of the Partnership’s income taxes.

Prior to May 1, 2013, the financial statements of the Partnership include EGT, MRT and the non-rate regulated natural gas gathering, processing and treating operations, which were under common control by CenterPoint Energy, and a 50% interest in SESH. Through the Partnership's formation on May 1, 2013, CenterPoint Energy retained certain assets and liabilities and related balances in accumulated other comprehensive loss, historically held by the Partnership, such as certain notes payable—affiliated companies to CenterPoint Energy and benefit plan obligations. Additionally, the Partnership distributed a 25.05% interest in SESH to CenterPoint Energy, subject to future acquisition by the Partnership through put and call options discussed in Note 9. On May 1, 2013, OGE Energy and ArcLight indirectly contributed 100% of the equity interests in Enogex to the Partnership in exchange for limited partner interests and, for OGE Energy only, interests in Enable GP. The Partnership concluded that the Partnership formation on May 1, 2013 was considered a business combination, and for accounting purposes, the Partnership was the acquirer of Enogex. Subsequent to May 1, 2013, the financial statements of the Partnership are consolidated to reflect the formation of the Partnership and the acquisition of Enogex. See Note 3 for further discussion of the acquisition of Enogex. For the period from May 1, 2013 through May 29, 2014, the financial statements reflect a 24.95% interest in SESH. For the period of May 30, 2014 through December 31, 2014, the financial statements reflect a 49.90% interest in SESH. See Note 9 for further discussion of SESH.

In addition, at December 31, 2014, as a result of the acquisition of Enogex on May 1, 2013, the Partnership held a 50% ownership interest in Atoka Midstream LLC (Atoka). At December 31, 2014, the Partnership consolidated Atoka in its Combined and Consolidated Financial Statements as Enable Oklahoma acted as the managing member of Atoka and had control over the operations of Atoka.

On April 16, 2014, the Partnership completed the Offering of 25,000,000 common units, representing limited partner interests in the Partnership, at a price to the public of $20.00 per common unit. The Partnership received net proceeds of $464 million from the sale of the common units, after deducting underwriting discounts and commissions, the structuring fee and offering expenses. In connection with the Offering, underwriters exercised their option to purchase 3,750,000 additional common units, which were fulfilled with units held by ArcLight. As a result, the Partnership did not receive any proceeds from the sale of common units pursuant to the exercise of the underwriters' option to purchase additional common units. The exercise of the underwriters' option to purchase additional common units did not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all outstanding units. The Partnership retained the net proceeds of the Offering for general partnership purposes, including the funding of expansion capital expenditures, and to pre-fund demand fees expected to be incurred over the next three years relating to certain expiring transportation and storage contracts. In connection with the Offering, 139,704,916 of CenterPoint Energy's common units and 68,150,514 of OGE Energy's common units were converted into subordinated units.

Basis of Presentation

The accompanying combined and consolidated financial statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP. For accounting and financial reporting purposes, (i) the formation of the Partnership is considered a contribution of real estate by CenterPoint Energy and is reflected at CenterPoint Energy’s historical cost as of May 1, 2013 and (ii) the Partnership acquired Enogex on May 1, 2013.

The combined and consolidated financial statements have been prepared from the historical accounting records maintained by CenterPoint Energy for the Partnership until May 1, 2013 and may not necessarily be indicative of the condition that would have existed or the results of operations if the Partnership had been operated as a separate and unaffiliated entity. All of the Partnership’s historical combined entities were under common control and management for the periods presented until May 1, 2013, and all intercompany transactions and balances are eliminated in combination and consolidation, as applicable. Beginning on May 1, 2013, the Partnership consolidated Enogex and all previously combined entities of the Partnership.

For a description of the Partnership’s reportable segments, see Note 17.

Use of Estimates

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

Revenues

Revenues for gathering, processing, transportation and storage services for the Partnership are recorded each month based on the current month’s estimated volumes, contracted prices (considering current commodity prices), historical seasonal fluctuations and any known adjustments. The estimates are reversed in the following month and customers are billed on actual volumes and contracted prices. Gas sales are calculated on current-month nominations and contracted prices. Revenues associated with the production of NGLs are estimated based on current-month estimated production and contracted prices. These amounts are reversed in the following month and the customers are billed on actual production and contracted prices. Estimated revenues are reflected in Accounts Receivable or Accounts Receivable-affiliated companies, as appropriate, on the Consolidated Balance Sheets and in Revenues on the Combined and Consolidated Statements of Income.

The Partnership recognizes revenue from natural gas gathering, processing, transportation and storage and crude oil gathering services to third parties as services are provided. Revenue associated with NGLs is recognized when the production is sold. The partnership records deferred revenue when it receives consideration from a third party before achieving certain criteria that must be met for revenue to be recognized in accordance with GAAP. The Partnership has $18 million and $9 million of deferred revenues on the Consolidated Balance Sheets as of December 31, 2014 and 2013, respectively.

The Partnership relies on certain key natural gas producer customers for a significant portion of natural gas and NGLs supply. The Partnership relies on certain key utilities for a significant portion of transportation and storage demand. The Partnership depends on third-party facilities to transport and fractionate NGLs that it delivers to third parties at the inlet of their facilities. Additionally for the years ended December 31, 2014 and 2013, one third party purchased approximately 21% and 30%, respectively, of the NGLs delivered off our system, which accounted for approximately $235 million and $232 million or 7% and 9%, respectively, of total revenue. Other than revenues from affiliates discussed in Note 13, there are no other revenue concentrations with individual customers in the years ended December 31, 2014, 2013, and 2012.

Natural Gas Purchases

Estimates for gas purchases are based on estimated volumes and contracted purchase prices. Estimated gas purchases are included in Accounts Payable or Accounts Payable-affiliated companies, as appropriate, on the Consolidated Balance Sheets and in Cost of Goods Sold, excluding Depreciation and Amortization on the Combined and Consolidated Statements of Income.

Environmental Costs

The Partnership expenses or capitalizes environmental expenditures, as appropriate, depending on their future economic benefit. The Partnership expenses amounts that relate to an existing condition caused by past operations that do not have future economic benefit. The Partnership records undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. There are no material amounts accrued at December 31, 2014 or 2013.

Depreciation and Amortization Expense

Depreciation is computed using the straight-line method based on economic lives or a regulatory-mandated recovery period. Amortization of intangible assets is computed using the straight-line method over the respective lives of the intangible assets.

The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets at the time the assets are placed in service. As circumstances warrant, useful lives are adjusted when changes in planned use, changes in estimated production lives of affiliated natural gas basins or other factors indicate that a different life would be more appropriate. Such changes could materially impact future depreciation expense. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively. The computation of amortization expense on intangible assets requires judgment regarding the amortization method used. Intangible assets are amortized on a straight-line basis over their useful lives using a method of amortization that reflects the pattern in which the economic benefits of the intangible asset are consumed.

During 2013, the Partnership completed a depreciation study for the Gathering and Processing segment, as well as the acquired Enogex assets. The new depreciation rates have been applied prospectively. There were no material changes in weighted average useful lives for pre-acquisition Gathering and Processing assets.

Income Taxes

Prior to May 1, 2013, the Partnership was included in the consolidated income tax returns of CenterPoint Energy. The Partnership calculated its income tax provision on a separate return basis under a tax sharing agreement with CenterPoint Energy. The Partnership used 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 were 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 was established against deferred tax assets for which management believed realization was not considered more likely than not. Current federal and certain state income taxes were payable to or receivable from CenterPoint Energy. The Partnership recognized interest and penalties as a component of income tax expense. Upon conversion to a limited partnership on May 1, 2013, the Partnership’s earnings are no longer subject to income tax (other than Texas state margin taxes and taxes associated with the Partnership's corporate subsidiary) and are taxable at the individual partner level. For more information, see Note 15.

Cash and Cash Equivalents

The Partnership considers cash equivalents to be short-term, highly liquid investments with maturities of three months or less from the date of purchase. The Consolidated Balance Sheets have $12 million and $108 million of cash and cash equivalents as of December 31, 2014 and 2013, respectively.

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. Based on this review, management determined that no allowance for doubtful accounts was required as of December 31, 2014 and 2013.

Inventory

Materials and supplies inventory is valued at cost and is subsequently recorded at the lower of cost or market. During the years ended December 31, 2014 and 2013, the Partnership recorded write-downs to market value related to materials and supplies inventory disposed or identified as excess or obsolete of $9 million and $2 million, respectively. No such write-down was recorded in the year ended December 31, 2012. Materials and supplies are recorded to inventory when purchased and, as appropriate, subsequently charged to operation and maintenance expense on the Combined and Consolidated Statements of Income or capitalized to property, plant and equipment on the Consolidated Balance Sheets when installed.

Natural gas inventory is held, through the Transportation and Storage segment, to provide operational support for the intrastate pipeline deliveries and to manage leased intrastate storage capacity. Natural gas liquids inventory is held, through the Gathering and Processing segment, due to timing differences between the production of certain natural gas liquids and ultimate sale to third parties. Natural gas and natural gas liquids inventory is valued using moving average cost and is subsequently recorded at the lower of cost or market. During the years ended December 31, 2014 and 2013, the Partnership recorded write-downs to market value related to natural gas and natural gas liquids inventory of $4 million and $4 million, respectively. No such write-down was recorded in the year ended December 31, 2012. The cost of gas associated with sales of natural gas and natural gas liquids inventory is presented in Cost of goods sold, excluding depreciation and amortization on the Combined and Consolidated Statements of Income.



	December 31,
	2014		2013
	(In millions)
Materials and supplies	$	39	$	60
Natural gas and natural gas liquids inventories	24		23
Total	$	63	$	83

Gas Imbalances

Gas imbalances occur when the actual amounts of natural gas delivered from or received by the Partnership’s pipeline system differ from the amounts scheduled to be delivered or received. Imbalances are due to or due from shippers and operators and can be settled in cash or made up in-kind depending on contractual terms. The Partnership values all imbalances at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value.

Long-Lived Assets (including Intangible Assets)

The Partnership records property, plant and equipment and intangible assets at historical cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and capitalized interest. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances and charged to Accumulated Depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation and the remaining balance net of any salvage proceeds is recorded as a loss in the Consolidated Statements of Income as Operation and Maintenance Expense. The Partnership expenses repair and maintenance costs as incurred. Repair, removal and maintenance costs are included in the Consolidated Statements of Income as Operation and Maintenance Expense.

Assessing Impairment of Long-lived Assets (including Intangible Assets) and Goodwill

The Partnership periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles other than goodwill, 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, as compared to the carrying value of the assets.

The Partnership assesses its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. The Partnership tested its goodwill for impairment on May 1, 2013 upon formation and following formation tests annually on October 1. The Partnership utilizes the market or income approaches to estimate the fair value of the reporting unit, also giving consideration to the alternative cost approach. Under the market approach, historical and current year forecasted cash flows are multiplied by a market multiple to determine fair value. Under the income approach, anticipated cash flows over a period of years plus a terminal value are discounted to present value using appropriate discount rates. 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. The Partnership performs its goodwill impairment testing one level below the Transportation and Storage and Gathering and Processing segment level at the operating segment level.

Regulatory Assets and Liabilities

The Partnership applies the guidance for accounting for regulated operations to portions of the Transportation and Storage segment. The Partnership’s rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. As of each of December 31, 2014 and 2013, these removal costs of $16 million are classified as regulatory liabilities in the Consolidated Balance Sheets.

Capitalization of Interest and Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases both utility plant and earnings, it is realized in cash when the assets are included in rates for combined entities that apply guidance for accounting for regulated operations. Capitalized interest represents the approximate net composite interest cost of borrowed funds used for construction. Interest and AFUDC are capitalized as a component of projects under construction and will be amortized over the assets’ estimated useful lives. During the years ended December 31, 2014, 2013 and 2012, the Partnership capitalized interest and AFUDC of $8 million, $7 million and $2 million, respectively.

Derivative Instruments

The Partnership is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. At times, the Partnership utilizes derivative instruments such as physical forward contracts, financial futures and swaps to mitigate the impact of changes in commodity prices on its operating results and cash flows. Such derivatives are recognized in the Partnership’s Combined or Consolidated Balance Sheets at their fair value unless the Partnership elects hedge accounting or 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.

The Partnership’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.

Fair Value Measurements

The Partnership determines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As required, the Partnership utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy included in current accounting guidance. The Partnership generally applies the market approach to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.

Equity Based Compensation

The Partnership awards equity based compensation to officers, directors and employees under the Long Term Incentive Plan. All equity based awards to officers, directors and employees under the Long Term Incentive Plan, including grants of phantom units, performance units, and restricted units are recognized in the Combined and Consolidated Statements of Income based on their fair values. The fair value of the phantom units and restricted units are based on the closing market price of the Partnership’s common unit on the grant date. The fair value of the performance units is estimated on the grant date using a lattice-based valuation model that factors in information, including the expected distribution yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the phantom unit and restricted unit awards is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a vesting period. The vesting of the performance unit awards is also contingent upon the probable outcome of the market condition. Depending on forfeitures and actual vesting, the compensation expense recognized related to the awards could increase or decrease.

Reverse Unit Split

On March 25, 2014, the Partnership effected a 1 for 1.279082616 reverse unit split. All unit and per unit amounts presented within the combined and consolidated financial statements reflect the effects of the reverse unit split.

Second Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP

On April 16, 2014, in connection with the closing of the Offering of the Partnership, the Partnership amended and restated its First Amended and Restated Agreement of Limited Partnership to remove certain provisions that expired upon completion of the Offering. Following the Offering, ArcLight no longer has protective approval rights over certain material activities of the Partnership, including material increases in capital expenditures and certain equity issuances, entering into transactions with related parties and acquiring, pledging or disposing of certain material assets.

New Accounting Pronouncements	12 Months Ended
New Accounting Pronouncements	Dec. 31, 2014
Accounting Changes and Error Corrections [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements In May 2014, FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers," which supersedes the revenue recognition requirements in "Revenue Recognition (Topic 605)," and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. ASU 2014-09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, and is to be applied retrospectively, with early application not permitted. The Partnership is currently evaluating the new standard.

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6507316

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Direct Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6510796

Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 01
-Paragraph b
-Subparagraph 6
-Article 10

+ Details

Acquisition of Enogex

12 Months Ended

Dec. 31, 2014

Business Combinations [Abstract]

Acquisition of Enogex

Under the acquisition method, the fair value of the consideration transferred by the Partnership to OGE Energy and ArcLight for the contribution of Enogex in exchange for interest in the Partnership was allocated to the assets acquired and liabilities assumed on May 1, 2013 based on their estimated fair value. Enogex’s assets, liabilities and equity are recorded at their estimated fair value as of May 1, 2013, and beginning on May 1, 2013, the Partnership consolidated Enogex.

On May 1, 2013, in accordance with the MFA, CenterPoint Energy, OGE Energy, and ArcLight received 227,508,825 common units, 110,982,805 common units, and 51,527,730 common units, respectively, representing limited partner interests in the Partnership. The fair value of consideration transferred to OGE Energy and ArcLight in exchange for the contribution of Enogex consists of the fair value of the limited and, for OGE Energy only, general partner interests. The Partnership utilized the market approach to estimate the fair value of the limited partner interests, general partner interests and Atoka, also giving consideration to alternative methods such as the income and cost approaches as it relates to the underlying assets and liabilities. The primary inputs for the market valuation were the historical and current year forecasted cash flows and market multiple. The primary inputs for the income approach were forecasted cash flows and the discount rate. The primary inputs for the cost approach were costs for similar assets and ages of the assets. All fair value measurements of assets acquired and liabilities assumed were based on a combination of inputs that were not observable in the market and thus represented Level 3 inputs.

The Partnership incurred no acquisition related costs in the Combined and Consolidated Statement of Income based upon the terms in the MFA.

The following table summarizes the amounts recognized by the Partnership for the estimated fair value of assets acquired and liabilities assumed for the acquisition of the 100% interest in Enogex as of May 1, 2013 and is reconciled to the consideration transferred by the Partnership:



	Amounts Recognized as of May 1, 2013
	(In millions)
Assets
Current Assets	$	192
Property, plant and equipment	3,919
Goodwill	439
Other intangible assets	401
Other assets	21
Total assets	$	4,972

Liabilities
Current liabilities	$	393
Long-term debt	745
Other liabilities	20
Total liabilities	1,158
Less: Noncontrolling interest at fair value	26
Fair value of consideration transferred	$	3,788

The amounts of Enogex’s revenue, operating income, net income and net income attributable to the Partnership included in the Partnership’s Combined and Consolidated Statement of Income for the period from May 1, 2013 through December 31, 2013, before eliminations, are as follows (in millions):



Revenues	$	1,406
Operating income	92
Net income	77
Net income attributable to Enable Midstream Partners, LP	74

Impact on Depreciation

The property, plant and equipment acquired from Enogex have differing weighted average useful lives from the existing assets of the Partnership. These assets will be depreciated over a weighted average estimated useful life of 32 years.

Unaudited Pro forma Results of Operations

The Partnership’s pro forma results of operations in the combined entity had the acquisition of Enogex been completed on January 1, 2012 are as follows:



	Year ended December 31,
	2013		2012
	(In millions)
Unaudited pro forma results of operations:
Pro forma revenues	$	3,120	$	2,563
Pro forma operating income	487		558
Pro forma net income	1,638		433
Pro forma net income attributable to Enable Midstream Partners, LP	1,635		431

The unaudited pro forma consolidated results of operations include adjustments to:


•	Include the historical results of Enogex beginning on January 1, 2012;


•	Include incremental depreciation and amortization incurred on the step-up of Enogex’s assets;


•	Include adjustments to revenue and cost of sales to reflect Enogex purchase price adjustments for the recurring impact of certain loss contracts and deferred revenues; and


•	Include a reduction to interest expense for recognition of a premium on Enogex’s fixed rate senior notes.

The unaudited pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the consolidated operations.

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

+ References

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

Earnings Per Limited Partner Unit

12 Months Ended

Dec. 31, 2014

Earnings Per Share [Abstract]

Earnings Per Limited Partner Unit

Limited partners’ interest in net income attributable to the Partnership and basic and diluted earnings per unit reflect net income attributable to the Partnership for periods subsequent to its formation as a limited partnership on May 1, 2013, as no limited partner units were outstanding prior to this date.

Basic and diluted earnings per limited partner unit is calculated by dividing the limited partners’ interest in net income by the weighted average number of limited partner units outstanding during the period. Any common units issued during the period are included on a weighted average basis for the days in which they were outstanding. The dilutive effect of unit-based awards, as discussed in Note 16, was less than $0.01 per unit during the year ended December 31, 2014.

The following table illustrates the Partnership’s calculation of earnings per unit for common and subordinated limited partner units:



	Year Ended December 31,
	2014		2013		2012
	(In millions, except per unit data)
Net income attributable to Enable Midstream Partners, LP	$	530	$	1,615	$	316
Less general partner interest in net income	—		—		—
Limited partner interest in net income attributable to Enable Midstream Partners, LP	$	530	$	1,615	$	316
Net income allocable to common units	$	339	$	289	$	—
Net income allocable to subordinated units	191		—		—
Limited partner interest in net income attributable to Enable Midstream Partners, LP	$	530	$	289	$	—
Basic and diluted weighted average number of outstanding limited partner units
Common units	264		390		—
Subordinated units	148		—		—
Total	412		390		—
Basic and diluted earnings per limited partner unit
Common units	$	1.29	$	0.74	$	—
Subordinated units	$	1.28	$	—	$	—

Enable Midstream Partners, LP Parent Net Equity and Partners' Capital

12 Months Ended

Dec. 31, 2014

Equity [Abstract]

Enable Midstream Partners, LP Parent Net Equity and Partners' Capital

Enable Midstream Partners, LP Parent Net Equity and Partners’ Capital

Prior to May 1, 2013, Enable Midstream Partners, LP Parent Net Equity represents the investment of CenterPoint Energy in the Partnership. On April 30, 2013, immediately prior to formation of the limited partnership, while under common control, CenterPoint Energy completed equity transactions with the Partnership, whereby CenterPoint Energy made a cash contribution to the Partnership and retained certain assets and liabilities previously held by the Partnership, all of which were deemed to be transfers of net assets not constituting a transfer of a business, as follows:



	Amounts retained prior to May 1, 2013
	(In millions)
Contributions from (Distributions to) CenterPoint Energy
Cash	$	40
Pension and postretirement plans	22
Deferred financing cost	6
Investment in 25.05% of SESH (see Note 9)	(197		)
Increase in Notes payable-affiliated companies	(143		)
Decrease in Notes receivable-affiliated companies	(45		)
Income tax obligations, net	28
Net distributions to CenterPoint Energy prior to formation	$	(289	)

Effective May 1, 2013, Enable Midstream Partners, LP Partners’ Capital on the Consolidated Balance Sheet represents the net amount of capital, accumulated net income, contributions and distributions affecting the investments of CenterPoint Energy, OGE Energy, and ArcLight in the Partnership. On August 14, 2013 and November 14, 2013, the Partnership distributed $61 million and $120 million to the unitholders of record as of July 1, 2013 and October 1, 2013, respectively. On February 14, 2014, May 14, 2014 and August 14, 2014, the Partnership distributed $114 million, $155 million and $22 million to the unitholders of record as of January 1, 2014, April 1, 2014, and April 1, 2014, respectively in accordance with the Partnership's First Amended and Restated Agreement of Limited Partnership.

The Partnership's Second Amended and Restated Agreement of Limited Partnership requires that, within 45 days subsequent to the end of each quarter, the Partnership distribute all of its available cash (as defined in the Second Amended and Restated Agreement of Limited Partnership) to unitholders of record on the applicable record date. The Partnership did not make distributions for the period that began on April 1, 2014 and ended on April 15, 2014, the day prior to the closing of the Offering, other than the required distributions to CenterPoint Energy, OGE Energy, and ArcLight under the First Amended and Restated Agreement of Limited Partnership.

We paid or have authorized payment of the following quarterly cash distributions under the Second Amended and Restated Agreement of Limited Partnership during 2014 (in millions, except for per unit amounts):

Quarter Ended

Record Date

Payment Date

Per Unit Distribution

Total Cash Distribution

June 30, 2014 ⁽¹⁾

August 4, 2014

August 14, 2014

0.2464

104

September 30, 2014

November 4, 2014

November 14, 2014

0.3025

128

December 31, 2014

February 4, 2015

February 13, 2015

0.30875

130

_____________________


(1)	The quarterly distribution for three months ended June 30, 2014 was prorated for the period beginning immediately after the closing of the Partnership's Offering, April 16, 2014 through June 30, 2014.

General Partner Interest and Incentive Distribution Rights

Enable GP owns a non-economic general partner interest in the Partnership and thus will not be entitled to distributions that the Partnership makes prior to the liquidation of the Partnership in respect of such general partner interest. Enable GP currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash the Partnership distributes from operating surplus in excess of $0.330625 per unit per quarter. The maximum distribution of 50.0% does not include any distributions that Enable GP or its affiliates may receive on common units or subordinated units that they own.

Subordinated Units

All subordinated units are held by CenterPoint Energy and OGE Energy. These units are considered subordinated because during the subordination period, the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.2875 per common unit, which amount is defined in the partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units.

Subordination Period

The subordination period began on the closing date of the Offering and will extend until the first business day following the distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equal to or exceeding $1.15 per unit (the annualized minimum quarterly distribution) for each of the three consecutive, non-overlapping four-quarter periods immediately preceding June 30, 2017. Also, if the Partnership has paid distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equal to or exceeding $1.725 per unit (150 percent of the annualized minimum quarterly distribution) and the related distribution on the incentive distribution rights, for any four-consecutive-quarter period ending on or after June 30, 2015, the subordination period will terminate.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2014

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, plant and equipment includes the following:



	Weighted Average Useful Lives (Years)	December 31,
	Weighted Average Useful Lives (Years)	2014		2013
		(In millions)
Property, plant and equipment, gross:
Gathering and Processing	35	$	5,560	$	5,123
Transportation and Storage	37	4,300		4,300
Construction work-in-progress		604		232
Total		$	10,464	$	9,655
Accumulated depreciation:
Gathering and Processing		343		213
Transportation and Storage		539		452
Total accumulated depreciation		882		665
Property, plant and equipment, net		$	9,582	$	8,990

The Partnership recorded depreciation expense of $249 million, $194 million, and $106 million during the years ended December 31, 2014, 2013 and 2012, respectively.

Intangible Assets, Net

12 Months Ended

Dec. 31, 2014

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets, Net

Prior to May 1, 2013, the Partnership did not have any intangible assets. The Partnership recorded $401 million in intangible assets associated with customer relationships due to the acquisition of Enogex. Intangible assets by intangible asset class are as follows as of December 31, 2014:



	Acquisition of Enogex		Accumulated Amortization		Net Intangible Assets
	(In millions)
Customer relationships	$	401	$	45	$	356
Total	$	401	$	45	$	356

The Partnership determined that intangible assets related to customer relationships have a weighted average useful life of 15 years as of May 1, 2013. Intangible assets do not have any significant residual value or renewal options of existing terms. There are no intangible assets with indefinite useful lives.

The Partnership recorded amortization expense of $27 million and $18 million during the years ended December 31, 2014 and 2013, respectively. The following table summarizes the Partnership's expected amortization of intangible assets for each of the next five years:



	2015		2016		2017		2018		2019
	(In millions)
Expected amortization of intangible assets	$	27	$	27	$	27	$	27	$	27

Goodwill

12 Months Ended

Dec. 31, 2014

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill

The excess of the consideration transferred over the fair value of the net assets acquired is allocated to goodwill. The goodwill arising from the acquisition of Enogex consists largely of the synergies and economies of scale expected from combining the operations of the Partnership and Enogex. The Partnership determined that its reporting units are one level below the Gathering and Processing and Transportation and Storage segment level at the operating segment level.

Goodwill by reportable segment is as follows:



	December 31, 2012		Acquisition of Enogex⁽¹⁾		December 31, 2013		December 31, 2014
	(In millions)
Gathering and Processing	$	50	$	439	$	489	$	489
Transportation and Storage	579		—		579		579
Total	$	629	$	439	$	1,068	$	1,068

__________________________


(1)	See Note 3 for further discussion regarding the acquisition of Enogex.

The Partnership does not amortize goodwill but instead annually assesses goodwill for impairment. The Partnership performed an interim test upon formation as a limited partnership on May 1, 2013 and its annual impairment tests in the fourth quarters of 2014 and 2013, and the third quarter of 2012. The Partnership determined that no impairment charge for goodwill was required for the years ended December 31, 2014, 2013 and 2012. See Note 1 for further discussion regarding goodwill impairment testing.

Investment in Equity Method Affiliates

12 Months Ended

Dec. 31, 2014

Equity Method Investments and Joint Ventures [Abstract]

Investments in Equity Method Affiliates

The Partnership uses the equity method of accounting for investments in entities in which it has an ownership interest between 20% and 50% and exercises significant influence. Until May 1, 2013, the Partnership held a 50% investment in SESH, a 286-mile interstate natural gas pipeline, which was accounted for as an investment in equity method affiliates. On May 1, 2013, the Partnership distributed a 25.05% interest in SESH to CenterPoint Energy, retaining a 24.95% interest in SESH.

For the period May 1, 2013 through May 29, 2014, CenterPoint Energy indirectly owned a 25.05% interest in SESH. Pursuant to the MFA, that interest could be contributed to the Partnership upon exercise of certain put or call rights, under which CenterPoint Energy would contribute to the Partnership CenterPoint Energy’s retained interest in SESH at a price equal to the fair market value of such interest at the time the put right or call right is exercised. On May 13, 2014, CenterPoint Energy exercised its put right with respect to a 24.95% interest in SESH. Pursuant to the put right, on May 30, 2014, CenterPoint Energy contributed a 24.95% interest in SESH to the Partnership in exchange for 6,322,457 common units representing limited partner interests in the Partnership, which had a fair value of $161 million based upon the closing market price of the Partnership's common units. If CenterPoint Energy were to exercise its remaining put right or the Partnership were to exercise its remaining call right (which may be no earlier than June 2015), CenterPoint Energy’s retained interest in SESH would be contributed to the Partnership in exchange for consideration consisting of 25,341 limited partner units for a 0.1% interest in SESH and, subject to certain restrictions, a cash payment, payable either from CenterPoint Energy to the Partnership or from the Partnership to CenterPoint Energy, in an amount such that the total consideration exchanged is equal in value to the fair market value of the contributed interest in SESH, subject to adjustment for accretion and dilution events. Affiliates of Spectra Energy Corp own the remaining 50% interest in SESH. Pursuant to the terms of the SESH LLC Agreement, if, at any time, CenterPoint Energy has a right to receive less than 50% of our distributions through its limited partner interest in the Partnership and its economic interest in Enable GP, affiliates of Spectra Energy Corp will have the right to purchase our interest in SESH at fair market value. As of December 31, 2014, the Partnership owns a 49.90% interest in SESH.

In connection with CenterPoint Energy's exercise of its put right with respect to its 24.95% interest in SESH, the parties agreed to allocate the distributions for the second quarter on (i) the SESH interest acquired by Enable and (ii) the Enable units issued to CenterPoint Energy for the SESH interest pro rata based on the time each party held the relevant interest. On July 25, 2014, the Partnership received a $7 million distribution from SESH for the three month period ended June 30, 2014, representing the Partnership's 49.90% interest in SESH. Under the terms of the agreement, the Partnership made a payment of approximately $1 million to CenterPoint Energy related to the additional 24.95% interest during the quarter ending September 30, 2014.

On June 13, 2014, SESH made a special distribution of the proceeds of its $400 million senior note issuance, less debt issuance costs, which resulted in a $198 million return of investment to the Partnership. In August 2014, the Partnership contributed $187 million to SESH which was utilized to repay SESH's $375 million senior notes due August 2014, increasing the book value of Enable's 49.90% investment in SESH. The Partnership and other members of SESH intend to contribute or otherwise return the remaining special distribution to SESH as necessary for general SESH purposes, including capital expenditures associated with SESH's expansion plans.

Prior to July 2012, the Partnership owned a 50% interest in Waskom, a natural gas processing plant, which was accounted as an investment in equity method affiliates. On July 31, 2012, the Partnership 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 in cash. 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. The $273 million purchase price was allocated to the fair value of assets received as follows: $253 million to property, plant and equipment; $16 million to goodwill; and the remaining balance to other assets and liabilities. The original 50% interest held by Partnership in Waskom had a fair value of approximately $201 million prior to its acquisition of the additional 50% interest in Waskom, based on a discounted cash flow methodology (a level 3 valuation technique for which the key inputs are the discount rate and operating cash flow projections). The purchase of the additional 50% interest in Waskom was determined to be a business combination achieved in stages, and as such the Partnership recorded a pre-tax gain of approximately $136 million and goodwill of $8 million on July 31, 2012, which is the result of Partnership remeasuring its original 50% interest in Waskom to fair value. As a result of the purchase, Partnership combined its wholly owned investment in Waskom beginning on July 31, 2012, which included goodwill totaling $24 million, consisting of $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.

The Partnership includes equity in earnings of equity method affiliates under the Other Income (Expense) caption in the Combined and Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 2012.

Investment in Equity Method Affiliates:



	(In millions)
Balance as of December 31, 2012	$	405
Distributions to CenterPoint Energy	(196		)
Equity in earnings of equity method affiliate	15
Capitalized interest on investment in SESH	(2		)
Distributions from equity method affiliate	(24		)
Balance as of December 31, 2013	198
Interest acquisition of SESH	161
Return of investment from SESH refinancing	(198		)
Additional investment in SESH	187
Equity in earnings of equity method affiliate	20
Contributions to equity method affiliate	3
Distributions from equity method affiliate	(23		)
Balance as of December 31, 2014	$	348

Equity in Earnings of Equity Method Affiliates:



	Year Ended December 31,
	2014		2013		2012
	(In millions)
Waskom	$	—	$	—	$	5
SESH	20		15		26
Total	$	20	$	15	$	31

Distributions from Equity Method Affiliates:



	Year Ended December 31,
	2014		2013		2012
	(In millions)
Waskom	$	—	$	—	$	7
SESH ⁽¹⁾	$	23	$	24	$	32

_____________________


(1)	Excludes $198 million in special distributions for the return of investment in SESH for the year ended December 31, 2014.

Summarized financial information of SESH is presented below:



	December 31,
	2014			2013
	(In millions)
Balance Sheets:
Current assets	$	57		$	53
Property, plant and equipment, net	1,127			1,132
Other assets	3			—
Total assets	$	1,187		$	1,185
Current liabilities	$	19		$	20
Long-term debt	400			375
Members’ equity	768			790
Total liabilities and members’ equity	$	1,187		$	1,185
Reconciliation:
Investment in SESH	$	348		$	198
Less: Capitalized interest on investment in SESH	(2		)	(1		)
The Partnership’s share of members' equity	$	346		$	197



	Year Ended December 31,
	2014		2013		2012
	(In millions)
Income Statements:
Revenues	$	108	$	107	$	110
Operating income	69		66		71
Net income	48		47		52

Debt

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Debt

The following table presents the Partnership's outstanding debt as of December 31, 2014 and 2013.



	December 31,
	2014		2013
	(In millions)
Revolving Credit Facility	$	—	$	333
Commercial Paper	253		—
Term Loan Facility	—		1,050
Enable Oklahoma Term Loan	—		250
2019 Notes	500		—
2024 Notes	600		—
2044 Notes	550		—
Enable Oklahoma Senior Notes	250		450
Premium on Enable Oklahoma Senior Notes	28		37
Total debt	2,181		2,120
Less amount classified as short-term debt⁽¹⁾	253		204
Total long-term debt	$	1,928	$	1,916

___________________


(1)	Short-term debt includes $253 million of commercial paper as of December 31, 2014, and $200 million 6.875% senior notes due July 15, 2014, as of December 31, 2013.

Maturities of long-term debt, excluding unamortized premiums, are as follows:



	Long-term debt
	(In millions)
2015	$	—
2016	—
2017	—
2018	—
2019	500
Thereafter	1,400

Revolving Credit Facility

On May 1, 2013, the Partnership entered into a $1.4 billion, senior unsecured revolving credit facility (Revolving Credit Facility), in accordance with the terms of the MFA, discussed in Note 1, that is scheduled to expire on May 1, 2018. As of December 31, 2014, there were no principal advances and $2 million in letters of credit outstanding under the Revolving Credit Facility. However, as discussed below, commercial paper borrowings effectively reduce our borrowing capacity under this Revolving Credit Facility.

The Revolving Credit Facility permits outstanding borrowings to bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s applicable credit ratings. As of December 31, 2014, the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was 1.625% based on the Partnership’s credit ratings. In addition, the Revolving Credit Facility requires the Partnership to pay a fee on unused commitments. The commitment fee is based on the Partnership’s applicable credit rating from the rating agencies. As of December 31, 2014, the commitment fee under the Revolving Credit Facility was 0.25% per annum based on the Partnership’s credit ratings. The commitment fee is recorded as interest expense in the Partnership's Combined and Consolidated Statements of Income.

The Revolving Credit Facility contains a financial covenant requiring us to maintain a ratio of consolidated funded debt to consolidated EBITDA as defined under the Revolving Credit Facility as of the last day of each fiscal quarter of less than or equal to 5.00 to 1.00; provided that, for a certain period of time following the consummation by us or certain of our subsidiaries of any one or more related acquisitions with a purchase price of at least $50 million in the aggregate, the consolidated funded debt to consolidated EBITDA ratio as of the last day of each such fiscal quarter during such period would be permitted to be up to 5.50 to 1.00.

The Revolving Credit Facility also contains covenants that restrict us and certain subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of subsidiary indebtedness, incurrence of liens, transactions with affiliates, designation of subsidiaries as Excluded Subsidiaries (as defined in the Revolving Credit Facility), restricted payments, changes in the nature of their respective businesses and entering into certain restrictive agreements. Borrowings under the Revolving Credit Facility are subject to acceleration upon the occurrence of certain defaults, including, among others, payment defaults on such facility, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany) of $100 million or more in the aggregate, change of control, nonpayment of uninsured money judgments in excess of $100 million, and the occurrence of certain ERISA and bankruptcy events, subject where applicable to specified cure periods.

Commercial Paper

In January 2014, the Partnership commenced a commercial paper program, pursuant to which the Partnership is authorized to issue up to $1.4 billion of commercial paper. The commercial paper program is supported by our Revolving Credit Facility, and outstanding commercial paper effectively reduces our borrowing capacity thereunder. As of December 31, 2014, $253 million was outstanding under our commercial paper program. Any reduction in our credit ratings could prevent us from accessing the commercial paper markets.

Senior Notes

On May 27, 2014, the Partnership completed the private offering of $500 million 2.400% senior notes due 2019 (2019 Notes), $600 million 3.900% senior notes due 2024 (2024 Notes) and $550 million 5.000% senior notes due 2044 (2044 Notes), with registration rights. The Partnership received aggregate proceeds of $1.63 billion. Certain of the proceeds were used to repay the $1.05 billion senior unsecured term loan facility (Term Loan Facility), and certain of the proceeds were used to repay the Enable Oklahoma $250 million variable rate term loan and the Enable Oklahoma $200 million 6.875% senior notes due July 15, 2014, and for general corporate purposes. On July 15, 2014, the Partnership repaid the Enable Oklahoma $200 million 6.875% senior notes. A wholly owned subsidiary of CenterPoint Energy has guaranteed collection of the Partnership’s obligations under the 2019 Notes and 2024 Notes, on an unsecured subordinated basis, subject to automatic release on May 1, 2016.

The indenture governing the 2019 Notes, 2024 Notes and 2044 Notes contains certain restrictions, including, among others, limitations on our ability and the ability of our principal subsidiaries to: (i) consolidate or merge and sell all or substantially all of our and our subsidiaries’ assets and properties; (ii) create, or permit to be created or to exist, any lien upon any of our or our principal subsidiaries’ principal property, or upon any shares of stock of any principal subsidiary, to secure any debt; and (iii) enter into certain sale-leaseback transactions. These covenants are subject to certain exceptions and qualifications.

As of December 31, 2014, the Partnership’s debt included Enable Oklahoma’s $250 million 6.25% senior notes due March 2020 (the Enable Oklahoma Senior Notes). The Enable Oklahoma Senior Notes have $28 million unamortized premium at December 31, 2014, resulting in an effective interest rate of 5.6%, during the year ended December 31, 2014. These senior notes do not contain any financial covenants other than a limitation on liens. This limitation on liens is subject to certain exceptions and qualifications.

Term Loan Facilities

On May 1, 2013, the Partnership entered into a $1.05 billion, three-year senior unsecured term loan facility (Term Loan Facility), the proceeds of which were used to repay $1.05 billion of intercompany indebtedness owed to CenterPoint Energy. A wholly owned subsidiary of CenterPoint Energy had guaranteed collection of the Partnership’s obligations under the Term Loan Facility, which guarantee was subordinated to all senior debt of such wholly owned subsidiary of CenterPoint Energy. Certain of the proceeds from the issuance of the 2019 Notes and 2024 Notes were used to repay the Term Loan Facility.

Effective May 1, 2013 the Partnership’s debt included Enable Oklahoma’s $250 million variable rate term loan (Enable Oklahoma Term Loan). The Enable Oklahoma Term Loan permitted outstanding borrowings to bear interest at the London Interbank Offered Rate (LIBOR) and/or an alternate base rate, at Enable Oklahoma’s election, plus an applicable margin. The applicable margin was based on Enable Oklahoma’s applicable credit ratings. Certain of the proceeds from the issuance of the 2024 Notes and 2044 Notes were used to repay the Enable Oklahoma Term Loan.

Financing Costs

Unamortized debt expense of $17 million and $9 million at December 31, 2014 and December 31, 2013, respectively, is classified in Other Assets in the Consolidated Balance Sheets and is being amortized over the life of the respective debt. Unamortized premium on long-term debt of $28 million and $37 million at December 31, 2014 and December 31, 2013, respectively, is classified as either Long-Term Debt or Current Portion of Long-Term Debt, consistent with the underlying debt instrument, in the Consolidated Balance Sheets and is being amortized over the life of the respective debt.

The Partnership recorded a $4 million loss on extinguishment of debt associated with the retirement of the $1.05 billion Term Loan Facility and the Enable Oklahoma $250 million variable rate term loan, which is included in Other, net on the Combined and Consolidated Statement of Income.

As of December 31, 2014, the Partnership and Enable Oklahoma were in compliance with all of their debt agreements, including financial covenants.

Fair Value Measurements

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurements

Certain 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. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on the NYMEX and settled through a NYMEX clearing broker.

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. Instruments classified as Level 2 include over-the-counter NYMEX natural gas swaps, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX pricing, and over-the-counter WTI crude swaps for condensate sales.

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 the Partnership’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Partnership develops these inputs based on the best information available, including the Partnership’s own data.

The Partnership utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX or WTI published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX published market prices may be considered Level 1 if they are settled through a NYMEX clearing broker account with daily margining. Over-the-counter derivatives with NYMEX or WTI based prices are considered Level 2 due to the impact of counterparty credit risk. Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets that result in management’s best estimate of fair value. These contracts are classified as Level 3.

The Partnership 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 period ended December 31, 2014, there were no transfers between Level 1, 2, and Level 3 investments.

The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor’s Ratings Services and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.

Estimated Fair Value of Financial Instruments

The fair values of all accounts receivable, notes receivable, accounts payable and other such financial instruments on the Consolidated Balance Sheets are estimated to be approximately equivalent to their carrying amounts and have been excluded from the table below. The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments at December 31, 2014 and December 31, 2013.



	December 31, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-Term Debt
Long-term notes payable - affiliated companies (Level 2)	$	363	$	362	$	363	$	363
Revolving Credit Facility (Level 2)⁽¹⁾	—		—		333		333
Term Loan Facility (Level 2)	—		—		1,050		1,050
Enable Oklahoma Term Loan (Level 2)	—		—		250		250
Enable Oklahoma Senior Notes (Level 2)⁽²⁾	279		282		487		477
Enable Midstream Partners, LP, 2019, 2024 and 2044 Notes (Level 2)	1,649		1,592		—		—

___________________


(1)	Borrowing capacity is reduced by our borrowings outstanding under the commercial paper program. $253 million of commercial paper was outstanding as of December 31, 2014, and no amount was outstanding as of December 31, 2013.


(2)	No amount is included in the current portion of long term debt as of December 31, 2014, and $204 million is included as of December 31, 2013.

The fair value of the Partnership’s Long-term notes payable—affiliated companies, Revolving Credit Facility, Term Loan Facility, and Enable Oklahoma Term Loan, along with the Enable Oklahoma Senior Notes and Enable Midstream Partners, LP, 2019, 2024 and 2044 Notes, is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy.

Non-Financial Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment).

During the years ended December 31, 2014 and 2013, the Partnership remeasured the Service Star assets at fair value. At December 31, 2014, management reassessed the carrying value of the Service Star business line, a component of the Gathering and Processing segment which provides measurement and communication services to third parties, based upon the loss of customers during 2014. Upon formation as a private partnership on May 1, 2013, management of the Partnership reassessed the long-term strategy related to the Service Star business line. Based on forecasted future undiscounted cash flows management determined that the carrying value of the Service Star assets were not fully recoverable. The Partnership utilized the income approach (generally accepted valuation approach) to estimate the fair value of these assets. The primary inputs are forecast cash flows and the discount rate. The fair value measurement is based on inputs that are not observable in the market and thus represent level 3 inputs. Applying a discounted cash flow model to the property, plant and equipment and reviewing the associated materials and supplies inventory, during the years ended December 31, 2014 and 2013, the Partnership recognized a $7 million and $12 million impairment, respectively. The $7 million impairment consisted of a write-down of property plant, and equipment. The $12 million impairment consisted of a $10 million write-down of property, plant and equipment and a $2 million write-down of materials and supplies inventory considered either excess or obsolete.

Contracts with Master Netting Arrangements

Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset. The reporting entity’s choice to offset or not must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Consolidated Balance Sheets. The Partnership has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.

The following tables summarize the Partnership’s assets and liabilities that are measured at fair value on a recurring basis at December 31, 2014 and December 31, 2013:



December 31, 2014	Commodity Contracts						Gas Imbalances ⁽¹⁾
	Assets			Liabilities			Assets ⁽²⁾		Liabilities ⁽³⁾
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	33		$	4		$	—	$	—
Significant other observable inputs (Level 2)	2			—			40		$	12
Unobservable inputs (Level 3)	5			—			—		$	—
Total fair value	40			4			40		$	12
Netting adjustments	(4		)	(4		)	—		$	—
Total	$	36		$	—		$	40	$	12



December 31, 2013	Commodity Contracts						Gas Imbalances ⁽¹⁾
	Assets			Liabilities			Assets ⁽²⁾		Liabilities ⁽³⁾
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	1		$	2		$	—	$	—
Significant other observable inputs (Level 2)	—			1			8		10
Total fair value	1			3			8		10
Netting adjustments	(1		)	(2		)	—		—
Total	$	—		$	1		$	8	$	10

______________________

(1)

The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. Gas imbalances held by Enable Oklahoma are valued using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices. There were no netting adjustments as of December 31, 2014 and December 31, 2013.


(2)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $4 million and $2 million at December 31, 2014 and December 31, 2013, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.


(3)	Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1 million and $3 million at December 31, 2014 and December 31, 2013, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

- 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

Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

The Partnership is exposed to certain risks relating to its ongoing business operations. The primary risk managed using derivative instruments is commodity price risk. The Partnership is also exposed to credit risk in its business operations.

Commodity Price Risk

The Partnership has used forward physical contracts, commodity price swap contracts and commodity price option features to manage the Partnership’s commodity price risk exposures in the past. Commodity derivative instruments used by the Partnership are as follows:


•	NGL put options, NGL futures and swaps, and WTI crude futures and swaps for condensate sales are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements;


•	natural gas futures and swaps are used to manage the Partnership’s keep-whole natural gas exposure associated with its processing operations and the Partnership’s natural gas exposure associated with operating its gathering, transportation and storage assets; and


•	natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas exposure associated with its storage and transportation contracts and asset management activities.

Normal purchases and normal sales contracts are not recorded in Other Assets or Liabilities in the Consolidated Balance Sheets and earnings are recognized and recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by the Partnership’s operations and (ii) commodity contracts for the purchase and sale of NGLs produced by the Partnership’s gathering and processing business.

The Partnership recognizes its non-exchange traded derivative instruments as Other Assets or Liabilities in the Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and, therefore, are recorded at fair value on a net basis in Other Current Assets in the Consolidated Balance Sheets.

As of December 31, 2014 and 2013, the Partnership had no derivative instruments that were designated as cash flow or fair value hedges for accounting purposes.

Credit Risk

The Partnership is exposed to certain credit risks relating to its ongoing business operations. Credit risk includes the risk that counterparties that owe the Partnership money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Partnership may be forced to enter into alternative arrangements. In that event, the Partnership’s financial results could be adversely affected, and the Partnership could incur losses.

Derivatives Not Designated As Hedging Instruments

Derivative instruments not designated as hedging instruments for accounting purposes are utilized in the Partnership’s asset management activities. For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

Quantitative Disclosures Related to Derivative Instruments

The majority of natural gas physical purchases and sales not designated as hedges for accounting purposes are priced based on a monthly or daily index, and the fair value is subject to little or no market price risk. Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via the Partnership’s processing contracts, which are not derivative instruments.

As of December 31, 2014, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes.



	Gross Notional Volume
	Purchases	Sales
Natural gas—TBtu⁽¹⁾
Physical	4	32
Fixed futures/swaps	5	35
Basis futures/swaps	7	54
Condensate—MBbl⁽²⁾
Futures/swaps	—	12

____________________


(1)	91.2 percent of the natural gas contracts have durations of one year or less, 6.5 percent have durations of more than one year and less than two years and 2.2 percent have durations of more than two years.


(2)	100.0 percent of the condensate contracts have durations of one year or less.

As of December 31, 2013, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes.



	Gross Notional Volume
	Purchases	Sales
Natural gas—TBtu⁽¹⁾
Physical	7	43
Fixed futures/swaps	3	5
Basis futures/swaps	3	6

____________________


(1)	94.8 percent of the natural gas contracts have durations of one year or less, 2.5 percent have durations of more than one year and less than two years and 2.7 percent have durations of more than two years.

Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheet at December 31, 2014 are as follows:



		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities
		(In millions)
Derivatives not designated as hedging instruments
Natural gas
Financial futures/swaps	Other Current	$	34	$	4
Physical purchases/sales	Other Current	1		—
Condensate
Financial futures/swaps	Other Current	5		—
Total gross derivatives ⁽¹⁾		$	40	$	4

_____________________


(1)	See Note 11 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheet as of December 31, 2014.

The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheet at December 31, 2013 are as follows:



		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities
		(In millions)
Derivatives not designated as hedging instruments
Natural gas
Financial futures/swaps	Other Current	$	1	$	2
Physical purchases/sales	Other Current	—		1
Total gross derivatives ⁽¹⁾		$	1	$	3

_______________________


(1)	See Note 11 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheet as of December 31, 2013.

Income Statement Presentation Related to Derivative Instruments

The following tables present the effect of derivative instruments on the Partnership’s Consolidated Statement of Income.



	Amounts Recognized in Income
	Year Ended December 31,
	2014		2013			2012
	(In millions)
Natural gas physical purchases/sales gains (losses)	$	1	$	—		$	—
Natural gas financial futures/swaps gains (losses)	37		(1		)	—
NGL/Condensate financial futures/swaps gains (losses)	11		—			—
Total	$	49	$	(1	)	$	—

For derivatives not designated as hedges in the tables above, amounts recognized in income for the years ended December 31, 2014, 2013 and 2012, if any, are reported in Revenues.

Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody’s Investors Services or Standard & Poor’s Ratings Services were to lower the Partnership’s senior unsecured debt rating to a below investment grade rating, at December 31, 2014, the Partnership would have been required to post no cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position at December 31, 2014. In addition, the Partnership could be required to provide additional credit assurances in future dealings with third parties, which could include letters of credit or cash collateral.

- 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
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-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5624171-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-SubTopic 10
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-SubTopic 30
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-Paragraph 2
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Paragraph 5
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5579245-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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-Paragraph 4H
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 12: http://www.xbrl.org/2003/role/presentationRef
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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Reference 16: http://www.xbrl.org/2003/role/presentationRef
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Reference 17: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Related Party Transactions

12 Months Ended

Dec. 31, 2014

Related Party Transactions

The material related party transactions with CenterPoint Energy, OGE Energy and their respective subsidiaries are summarized below. There were no material related party transactions with other affiliates.

The Partnership’s revenues from affiliated companies accounted for 6%, 9%, and 14% of revenues during the years ended December 31, 2014, 2013, and 2012, respectively. Amounts of revenues from affiliated companies included in the Partnership’s Combined and Consolidated Statements of Income are summarized as follows:



	Year Ended December 31,
	2014		2013		2012
	(In millions)
Gas transportation and storage — CenterPoint Energy	$	112	$	108	$	133
Gas sales — CenterPoint Energy	22		70		—
Gas transportation and storage — OGE Energy ⁽¹⁾	39		32		—
Gas sales — OGE Energy⁽¹⁾	13		14		—
Total revenues — affiliated companies	$	186	$	224	$	133

____________________

(1)

The Partnership's contracts with OGE Energy to transport and sell natural gas to OGE Energy’s natural gas-fired generation facilities and store natural gas are reflected in Partnership’s Combined and Consolidated Statement of Income beginning on May 1, 2013. On March 17, 2014, the Partnership and the electric utility subsidiary of OGE Energy signed a new transportation agreement effective May 1, 2014 with a primary term through April 30, 2019. Following the primary term, the agreement will remain in effect from year to year thereafter unless either party provides notice of termination to the other party at least 180 days prior to the commencement of the succeeding annual period.

Amounts of natural gas purchased from affiliated companies included in the Partnership’s Combined and Consolidated Statements of Income are summarized as follows:



	Year Ended December 31,
	2014		2013		2012
	(In millions)
Cost of goods sold — CenterPoint Energy	$	2	$	4	$	1
Cost of goods sold — OGE Energy	19		8		—
Total cost of goods sold — affiliated companies	$	21	$	12	$	1

Prior to May 1, 2013, the Partnership had employees and reflected the associated benefit costs directly and not as corporate services. Under the terms of the MFA, effective May 1, 2013 the Partnership’s employees were seconded by CenterPoint Energy and OGE Energy, and the Partnership began reimbursing each of CenterPoint Energy and OGE Energy for all employee costs under the seconding agreements until the seconded employees transition from CenterPoint Energy and OGE Energy to the Partnership. The Partnership transitioned seconded employees from CenterPoint Energy and OGE Energy to the Partnership effective January 1, 2015, except for certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. The Partnership’s reimbursement of OGE Energy for employee costs arising out of OGE Energy’s defined benefit and retiree medical plans is fixed at $6 million in each of 2015 and 2016, $5 million in 2017, and at actual cost subject to a cap of $5 million in 2018 and thereafter, in the event of continued secondment.

Prior to May 1, 2013, the Partnership received certain services and support functions from CenterPoint Energy described below. Under the terms of the MFA, effective May 1, 2013, the Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under service agreements for an initial term ending on April 30, 2016. The service agreements automatically extend year-to-year at the end of the initial term, unless terminated by the Partnership with at least 90 days’ notice. Additionally, the Partnership may terminate these service agreements at any time with 180 days’ notice, if approved by the Board of Enable GP. The Partnership reimburses CenterPoint Energy and OGE Energy for these services up to annual caps, which for 2014 are $38 million and $28 million, respectively.

Effective April 1, 2014, the Partnership, CenterPoint Energy and OGE Energy agreed to reduce certain allocated costs charged to the Partnership because the Partnership has assumed responsibility for the related activities.

Amounts charged to the Partnership by affiliates for seconded employees and corporate services, included primarily in operating and maintenance expenses in Partnership’s Combined and Consolidated Statements of Income are as follows:



	Year Ended December 31,
	2014		2013		2012
	(In millions)
Seconded Employee Costs - CenterPoint Energy ⁽¹⁾	$	138	$	92	$	—
Corporate Services - CenterPoint Energy	29		38		39
Seconded Employee Costs - OGE Energy ⁽²⁾	105		78		—
Corporate Services - OGE Energy ⁽²⁾	17		18		—
Total corporate services and seconded employees expense	$	289	$	226	$	39

_________________________


(1)	Beginning on May 1, 2013, CenterPoint Energy assumed all employees of the Partnership and seconded such employees to the Partnership. Therefore, costs historically incurred directly by the Partnership for employment services are reflected as seconded employee costs subsequent to formation on May 1, 2013.


(2)	Corporate services and seconded employee expenses from OGE Energy are reflected in the Combined and Consolidated Statement of Income beginning on May 1, 2013.

The Partnership has outstanding long-term notes payable—affiliated companies to CenterPoint Energy at both December 31, 2014 and 2013 of $363 million which mature in 2017. Notes having an aggregate principal amount of approximately $273 million bear a fixed interest rate of 2.10% and notes having an aggregate principal amount of approximately $90 million bear a fixed interest rate of 2.45%.

The Partnership recorded affiliated interest expense to CenterPoint Energy on note payable—affiliated companies of $8 million, $34 million and $85 million, respectively during the year ended December 31, 2014, 2013 and 2012, respectively.

The Partnership recorded no interest income—affiliated companies from CenterPoint Energy on notes receivable—affiliated companies during the year ended December 31, 2014 and $9 million and $21 million, during the year ended December 31, 2013 and 2012, respectively.

- 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

Commitments and Contingencies

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

(a) Long-Term Agreements

Long-term Gas Gathering and Treating Agreements. The Partnership has long-term agreements with Encana and Vine to provide gathering and treating services for their natural gas production from certain Haynesville Shale and Bossier Shale formations in Texas and Louisiana.

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

Long-term Agreement with XTO. In March 2013, Enable Bakken entered into a long-term agreement with XTO to provide gathering services for certain of XTO’s crude oil production through a new crude oil gathering and transportation pipeline system in North Dakota’s liquids-rich Bakken Shale. The agreement with XTO was entered into pursuant to the open season announced by Enable Bakken in February 2013. Under the terms of the agreement, which includes volume commitments, Enable Bakken will provide service to XTO over a gathering system to be constructed by Enable Bakken in Dunn and McKenzie Counties in North Dakota with a capacity of up to 19,500 barrels per day. A majority of the pipeline system was placed in service during 2014 with the remaining portions expected to be placed in service in the first quarter of 2015. As of December 31, 2014, the Partnership estimates the remaining construction costs to be $53 million

Operating Lease Obligations. The Partnership has operating lease obligations expiring at various dates. Future minimum payments for noncancellable operating leases are as follows:



	Year Ended December 31,
	2015		2016		2017		2018		2019		After 2019		Total
	(In millions)
Noncancellable operating leases	$	12	$	7	$	3	$	3	$	1	$	—	$	26

Total rental expense for all operating leases was $23 million, $12 million and $16 million during the years ended December 31, 2014, 2013 and 2012, respectively.

The Partnership currently occupies 162,053 square feet of office space at its executive offices under a lease that expires June 30, 2019. The lease payments are $19 million over the lease term, which began April 1, 2012. This lease has rent escalations which increase after 5 years, and will further escalate after 10 years if the lease is renewed. These lease expenses are reflected in the Statement of Combined or Consolidated Income beginning on May 1, 2013.

The Partnership currently has 86 compression service agreements, of which 36 agreements are on a month-to-month basis, 24 agreements will expire in 2015, 20 agreements will expire in 2016 and 6 agreements will expire in 2017. The Partnership also has 8 gas treating agreements, of which 7 agreements are on a month-to-month basis and one agreement will expire in 2015. These lease expenses are reflected in the Statement of Combined or Consolidated Income beginning on May 1, 2013.

Other Purchase Obligations and Commitments. In 2004, Enable Oklahoma entered into a firm transportation service agreement with Cheyenne Plains, who operates the Cheyenne Plains Pipeline that provides firm transportation services in Wyoming, Colorado and Kansas, for 60,000 dekatherms/day of firm capacity on the pipeline. The firm transportation service agreement was for a 10-year term beginning with the in-service date of the Cheyenne Plains Pipeline in March 2005 with an annual demand fee of $7 million. Effective March 1, 2007, Enable Oklahoma and Cheyenne Plains amended the firm transportation service agreement to provide for Enable Oklahoma to turn back 20,000 dekatherms/day of its capacity beginning in January 2008 for the remainder of the term.

In 2006, Enable Oklahoma entered into a firm capacity agreement with Midcontinent Express Pipeline (MEP) for a primary term of 10 years (subject to possible extension) that gives MEP and its shippers’ access to capacity on Enable Oklahoma’s system. The quantity of capacity subject to the MEP capacity agreement is currently 272 MMcf/d, with the quantity subject to being increased by mutual agreement pursuant to the capacity agreement.

The Partnership’s other future purchase obligations and commitments estimated for the next five years are as follows:



	Year Ended December 31,
	2015		2016		2017		2018		2019		Total
	(In millions)
Other purchase obligations and commitments	$	5	$	1	$	—	$	—	$	—	$	6

(b) Legal, Regulatory and Other Matters

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

Income Taxes

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Income Taxes

Upon conversion to a limited partnership on May 1, 2013, the Partnership’s earnings are generally no longer subject to income tax (other than Texas state margin taxes and taxes associated with the Partnership's corporate subsidiary) and are taxable at the individual partner level, with the exception of Enable Midstream Services, LLC, a wholly owned subsidiary (Enable Midstream Services). The Partnership and its subsidiaries are pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in the combined and consolidated financial statements. Consequently, the Combined and Consolidated Statements of Income do not include an income tax provision for income earned on or after May 1, 2013 (other than Texas state margin taxes and taxes associated with the Partnership's corporate subsidiary).

The items comprising income tax expense are as follows:



	Year Ended December 31,
	2014		2013			2012
	(In millions)
Provision (benefit) for current income taxes
Federal	$	—	$	1		$	6
State	1		1			1
Total provision (benefit) for current income taxes	1		2			7
Provision (benefit) for deferred income taxes, net
Federal	$	—	(1,039		)	$	164
State	1		(155		)	32
Total provision (benefit) for deferred income taxes, net	1		(1,194		)	196
Total income tax expense (benefit)	$	2	$	(1,192	)	$	203

The following schedule reconciles the statutory Federal income tax rate to the effective income tax rate:



	Year Ended December 31,
	2014			2013			2012
	(In millions)
Income before income taxes	$	535		$	426		$	519
Federal statutory rate	—		%	35		%	35		%
Expected federal income tax expense	—			149			182
Increase in tax expense resulting from:
State income taxes, net of federal income tax	2			8			21
Income not subject to tax	—			(103		)	—
Conversion to partnership	—			(1,240		)	—
Other, net	—			(6		)	—
Total	2			(1,341		)	21
Total income tax expense (benefit)	$	2		$	(1,192	)	$	203
Effective tax rate	0.4		%	(275.9		)%	39.1		%

As a result of the conversion to a limited partnership, CenterPoint Energy assumed all outstanding current income tax liabilities and the deferred income tax assets and liabilities were eliminated by recording a provision for income tax benefit equal to $1.24 billion. Therefore there were no federal deferred income tax assets and liabilities balances at December 31, 2014 and 2013.

Enable Midstream Services is subject to U.S. federal and state income taxes. Deferred income tax assets and liabilities for the operations of this corporation are recognized for temporary differences between the assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective.

The components of Deferred Income Taxes as of December 31, 2014 and 2013 were as follows:



	December 31,
	2014		2013
	(In millions)
Deferred tax assets:	$	—	$	—
Deferred tax liabilities:
Non-current:
Depreciation	9		8
Total non-current deferred tax liabilities	9		8
Accumulated deferred income taxes, net	$	9	$	8

Uncertain Income Tax Positions

The following table reconciles the beginning and ending balance of the Partnership’s unrecognized tax benefits:



	December 31,
	2014		2013		2012
	(In millions)
Balance, beginning of year	$	—	$	—	$	3
Tax Positions related to prior years:
Reductions	—		—		(3		)
Balance, end of year	$	—	$	—	$	—

The Partnership’s unrecognized tax benefits on uncertain tax positions would not affect the effective income tax rate if they were recognized. The Partnership recognizes interest and penalties as a component of income tax expense. There were no unrecognized tax benefits as of December 31, 2014, 2013 and 2012.

Tax Audits and Settlements

CenterPoint Energy’s consolidated federal income tax returns have been audited by the IRS and settled through the 2011 tax year. CenterPoint Energy is currently under examination by the IRS for tax year 2012 and 2013. The Partnership considered the effect of this examination in its accrual for settled issues and liability for uncertain income tax positions as of December 31, 2013. The federal income tax return of the Partnership is currently under examination for the 2013 tax year. Because the Partnership is generally not subject to income tax we do not anticipate the results of the IRS examination will have a material financial impact to the company.

Equity Based Compensation

12 Months Ended

Dec. 31, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Equity Based Compensation

Enable GP has adopted the Enable Midstream Partners, LP Long Term Incentive Plan for officers, directors and employees of the Partnership, Enable GP or affiliates, including any individual who provides services to the Partnership or Enable GP as a seconded employee, and any consultants or affiliates of Enable GP or other individuals who perform services for the Partnership.

The long term incentive plan consists of the following components: phantom units, performance units, appreciations rights, restricted units, option rights, cash incentive awards, distribution equivalent rights or other unit-based awards and unit awards. The purpose of awards under the long term incentive plan is to provide additional incentive compensation to employees providing services to the Partnership, and to align the economic interests of such employees with the interests of unitholders. The long term incentive plan will limit the number of units that may be delivered pursuant to vested awards to 13,100,000 common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units cancelled, forfeited, expired or cash settled will be available for delivery pursuant to other awards. The plan is administered by the Board of Directors or a designated committee thereof.

The following table summarizes the Partnership’s compensation expense for the years ended December 31, 2014, 2013, and 2012 related to performance units, restricted units, and phantom units.



	Year Ended December 31,
	2014		2013		2012
	(In millions)
Performance units	$	3	$	—	$	—
Restricted units	10		—
Phantom units	2		—		—
Total compensation expense	$	15	$	—	$	—

Performance Units

On June 2, 2014, 563,963 performance based phantom units (performance units) were granted under the Long Term Incentive Plan pursuant to the 2014 Long Term Incentive Plan Annual Award Program, to certain employees providing services to the Partnership, including executive officers, that cliff vest three years from the grant date. The performance units provide for accelerated vesting if there is a change in control (as defined in the Enable Midstream Partners, LP Long Term Incentive Plan). Each performance unit is subject to forfeiture if the recipient terminates employment with the Partnership prior to the end of the three-year award cycle for any reason other than death, disability or retirement. In the event of death or disability, a participant will receive a payment based on the targeted achievement of the performance goals during the award cycle. In the event of retirement, a participant will receive a pro rated payment based on the actual performance of the performance goals during the award cycle.

The payment of performance units is dependent upon the Partnership's total unitholder return ranking relative to a peer group of companies over the period of April 11, 2014 through December 31, 2016 as compared to a target set at the time of the grant by the Board of Directors. Any performance units that cliff vest three years from the grant date (i.e. the three year award cycle) will be payable in the Partnership's common units. All of these performance units are classified as equity in the Partnership's Consolidated Balance Sheet. If there is no or only a partial payout for the performance units at the end of the award cycle, the unearned performance units are cancelled. Payout requires approval of the Board of Directors.

The fair value of the performance units was estimated on the grant date using a lattice-based valuation model that factors in information, including the expected distribution yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the performance units is a fixed amount determined at the grant date fair value and is recognized over the three-year award cycle regardless of whether performance units are awarded at the end of the award cycle. Distributions are accumulated and paid at vesting, and therefore, are not included in the fair value calculation. Due to the short trading history of the Partnership's common units, expected price volatility is based on the average of the three-year volatility of the peer group companies used to determine the total unitholder return ranking. The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant. The expected life of the units is based on the non-vested period since inception of the award cycle. There are no post-vesting restrictions related to the Partnership’s performance units. The number of performance units granted based on total unitholder return and the assumptions used to calculate the grant date fair value of the performance units based on total unitholder return are shown in the following table.



	2014
Number of units granted	563,963
Fair value of units granted	$	26.12
Expected price volatility	22.2		%
Risk-free interest rate	0.83		%
Expected life of units (in years)	3.00

Restricted Units

On April 16, 2014, 375,000 restricted units were granted to the Chief Executive Officer of Enable GP, of which 40% vested on August 1, 2014 and 20% vested on February 1, 2015 and 20% will vest on each of February 1, 2016 and 2017. Additionally, on April 16, 2014, the Board of Directors granted 150,000 restricted units to the Chief Executive Officer of Enable GP, which vest four years from the grant date. On April 16, 2014, 137,500 restricted units were granted to the Chief Financial Officer of Enable GP, which vest 45.46% on March 1, 2015 and 54.54% on March 1, 2016. Additionally, on April 16, 2014, 25,000 restricted units were granted to the Chief Financial Officer of Enable GP, which vest four years from the grant date. Prior to vesting, each share of restricted stock is subject to forfeiture if the recipient ceases to render substantial services to the Partnership for any reason other than death, disability or retirement. During the restriction period these units may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture.

The Board of Directors has also authorized various grants of time-based restricted units (restricted units) to certain employees providing services to the Partnership that are subject to cliff vesting over various terms, not longer than four years from the grant date. Prior to vesting, each share of restricted stock is subject to forfeiture if the recipient ceases to render substantial services to the Partnership for any reason other than death, disability or retirement. During the restriction period these units may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture.

The fair value of the restricted units was based on the closing market price of the Partnership’s common unit on the grant date. Compensation expense for the restricted units is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a vesting period, as defined in the agreements. Distributions are paid as declared prior to vesting and, therefore, are included in the fair value calculation. After payment, distributions are not subject to forfeiture. The expected life of the restricted units is based on the non-vested period since inception of the award cycle. There are no post-vesting restrictions related to the Partnership's restricted units. The number of restricted units granted related to the Partnership’s employees and the grant date fair value are shown in the following table.



	2014
Restricted units granted on April 16, 2014 to the Chief Executive Officer and Chief Financial Officer of Enable GP	687,500
Fair value of restricted units granted	$	22.60

Restricted units granted to the Partnership's employees	304,901
Fair value of restricted units granted	$23.56 - $25.50

Phantom Units

On April 21, 2014, 100,000 time-based phantom units (phantom units) were granted to certain employees providing services to the Partnership, including executive officers, that vest on the first anniversary of the date of grant. Prior to vesting, each share of restricted units is subject to forfeiture if the recipient ceases to render substantial services to the Partnership for any reason other than death, disability or retirement. During the restriction period these units may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture.

During 2014, the Board of Directors granted 6,718 phantom units to the independent directors of Enable GP, for their service as directors, which vest one year from the grant date.

The fair value of the phantom units was based on the closing market price of the Partnership’s common unit on the grant date. Compensation expense for the phantom unit is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a one-year vesting period. Distributions are accumulated and paid at vesting and, therefore, are not included in the fair value calculation. The expected life of the phantom unit is based on the non-vested period since inception of the one-year award cycle. There are no post-vesting restrictions related to the Partnership's phantom unit. The number of phantom units granted and the grant date fair value are shown in the following table.



	2014
Phantom units granted	106,718
Fair value of phantom units granted	$23.16 - $23.70

Units Outstanding

A summary of the activity for the Partnership's performance units, restricted units, and phantom units as of December 31, 2014 and changes in 2014 are shown in the following table.



	Performance Units				Restricted Stock				Phantom Units
	Number of Units		Aggregate Intrinsic Value		Number of Units		Aggregate Intrinsic Value		Number of Units		Aggregate Intrinsic Value
	(In millions, except unit data)
Units Outstanding at 12/31/2013	—				—				—
Granted⁽¹⁾	563,963				992,401				106,718
Vested	(1,545	)			(150,515	)			(500	)
Forfeited	(9,837	)			(3,818	)			(7,500	)
Units Outstanding at 12/31/2014	552,581		$	11	838,068		$	16	98,718		$	2
Units Fully Vested at 12/31/2014	1,545		$	—	150,515		$	—	500		$	—

_____________________


(1)	For performance units, this represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target.

Unrecognized Compensation Cost

A summary of the Partnership's unrecognized compensation cost for its non-vested performance units, restricted units, and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.



	December 31, 2014
	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance Units	$	11	2.81
Restricted Units	13		1.89
Phantom Units	1		0.36
Total	$	25

As of December 31, 2014, there were 11,458,073 units available for issuance under the long term incentive plan.

Reportable Business Segments

12 Months Ended

Dec. 31, 2014

Segment Reporting [Abstract]

Reportable Business Segments

Reportable Segments

The Partnership’s determination of reportable segments considers the strategic operating units under which it 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 reportable segments are the same as those described in the summary of significant accounting policies described in Note 1, which explain that some executive benefit costs of the Partnership prior to May 1, 2013 have not been allocated to reportable segments. The Partnership uses operating income as the measure of profit or loss for its reportable segments.

The Partnership’s assets and operations are organized into two reportable segments: (i) Gathering and Processing, which primarily provides natural gas gathering, processing and fractionation services and crude oil gathering for our producer customers, and (ii) Transportation and Storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to natural gas producers, utilities and industrial customers. Effective May 1, 2013, the intrastate natural gas pipeline operations acquired from Enogex were combined with the interstate pipelines in the transportation and storage segment and the non-rate regulated natural gas gathering, processing and treating operations acquired from Enogex were combined within the gathering and processing segment.

Financial data for segments and services are as follows:



Year Ended December 31, 2014	Gathering and Processing ⁽¹⁾		Transportation and Storage ⁽²⁾		Eliminations			Total
	(In millions)
Revenues⁽³⁾	$	2,424	$	1,577	$	(634	)	$	3,367
Cost of goods sold, excluding depreciation and amortization	1,585		961		(632		)	1,914
Operation and maintenance	297		232		(2		)	527
Depreciation and amortization	160		116		—			276
Impairment	8		—		—			8
Taxes other than income tax	25		31		—			56
Operating income	$	349	$	237	$	—		$	586
Total assets	$	8,356	$	5,493	$	(2,012	)	$	11,837
Capital expenditures	$	740	$	103	$	(6	)	$	837



Year Ended December 31, 2013	Gathering and Processing ⁽¹⁾		Transportation and Storage ⁽²⁾		Eliminations			Total
	(In millions)
Revenues⁽³⁾	$	1,740	$	1,149	$	(400	)	$	2,489
Cost of goods sold, excluding depreciation and amortization	1,075		636		(398		)	1,313
Operation and maintenance	222		209		(2		)	429
Depreciation and amortization	117		95		—			212
Impairment	12		—		—			12
Taxes other than income tax	20		34		—			54
Operating income	$	294	$	175	$	—		$	469
Total assets	$	7,157	$	5,717	$	(1,642	)	$	11,232
Capital expenditures	$	431	$	142	$	—		$	573



Year Ended December 31, 2012	Gathering and Processing ⁽¹⁾		Transportation and Storage⁽²⁾		Eliminations			Total
	(In millions)
Revenues⁽³⁾	$	502	$	502	$	(52	)	$	952
Cost of goods sold, excluding depreciation and amortization	124		55		(50		)	129
Operation and maintenance	114		155		(2		)	267
Depreciation and amortization	50		56		—			106
Taxes other than income tax	5		29		—			34
Operating income	$	209	$	207	$	—		$	416
Total assets	$	2,439	$	4,052	$	(9	)	$	6,482
Capital expenditures	$	70	$	132	$	—		$	202

_____________________

(1)

Gathering and processing recorded equity income of $0 million, $0 million and $5 million for each of the years ended December 31, 2014, 2013 and 2012, respectively, from its 50% interest in a jointly-owned gas processing plant, Waskom. These amounts are included in Equity in earnings of equity method affiliates under the Other income (expense) caption. The Partnership consolidated Waskom during the third quarter of 2012. See Note 9 for further discussion regarding Waskom.

(2)

Transportation and Storage recorded equity income of $20 million, $15 million and $26 million for each of the years ended December 31, 2014, 2013 and 2012, respectively, from its interest in SESH, a jointly-owned pipeline. These amounts are included in Equity in earnings of equity method affiliates under the Other Income (Expense) caption. Transportation and Storage’s investment in SESH was $348 million and $198 million as of December 31, 2014 and December 31, 2013, respectively, and is included in Investments in equity method affiliates. The Partnership reflected a 50% interest in SESH until May 1, 2013 when the Partnership distributed a 25.05% interest in SESH to CenterPoint Energy. For the period of May 1, 2013 through May 29, 2014 the Partnership reflected a 24.95% interest in SESH. On May 30, 2014, CenterPoint Energy contributed its 24.95% interest in SESH to the Partnership. As of December 31, 2014, the Partnership owns 49.90% interest in SESH. See Note 9 for further discussion regarding SESH.


(3)	The Partnership had no external customers accounting for 10% or more of revenues in periods shown. See Note 13 for revenues from affiliated companies.

- 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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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2014 and 2013 are as follows:



	Quarters Ended
	March 31, 2014		June 30, 2014		September 30, 2014		December 31, 2014
	(in millions, except per unit data)
Revenues (including revenues from affiliates (Note 13))	$	1,002	$	827	$	803	$	735
Cost of Goods Sold, excluding depreciation and amortization (including expenses from affiliates (Note 13))	633		478		439		364
Operating income	162		138		152		134
Net income	150		121		139		123
Net income attributable to Enable Midstream Partners, LP	149		120		139		122

Basic and diluted earnings per common limited partner unit (Note 4)	$	0.38	$	0.29	$	0.33	$	0.29
Basic and diluted earnings per subordinated limited partner unit (Note 4)	$	—	$	0.29	$	0.33	$	0.29

	Quarters Ended
	March 31, 2013		June 30, 2013		September 30, 2013		December 31, 2013
	(in millions, except per unit data)
Revenues (including revenues from affiliates (Note 13))	$	261	$	612	$	792	$	824
Cost of Goods Sold, excluding depreciation and amortization (including expenses from affiliates (Note 13))	45		323		459		486
Operating income	108		116		115		130
Net income	59		1,338		105		116
Net income attributable to Enable Midstream Partners, LP	59		1,337		104		115

Basic and diluted earnings per common limited partner unit (Note 4)⁽¹⁾	$	—	$	0.18	$	0.27	$	0.29
Basic and diluted earnings per subordinated limited partner unit (Note 4)	$	—	$	—	$	—	$	—

____________________


(1)	Basic and diluted earnings per unit reflect net income attributable to the Partnership for periods subsequent to its formation as a limited partnership on May 1, 2013, as no limited partner units were outstanding prior to this date. See Note 4.

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization Enable Midstream Partners, LP (Partnership) is a Delaware limited partnership formed on May 1, 2013 by CenterPoint Energy, Inc. (CenterPoint Energy), OGE Energy Corp. (OGE Energy) and affiliates of ArcLight Capital Partners, LLC (ArcLight), pursuant to the terms of the MFA. The Partnership is a large-scale, growth-oriented limited partnership formed to own, operate and develop strategically located natural gas and crude oil infrastructure assets. The Partnership’s assets and operations are organized into two reportable segments: (i) Gathering and Processing, which primarily provides natural gas gathering, processing and fractionation services and crude oil gathering for our producer customers, and (ii) Transportation and Storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to natural gas producers, utilities and industrial customers. The natural gas gathering and processing assets are located in four states and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex basins. This segment also includes a crude oil gathering business in the Bakken Shale formation, principally located in the Williston basin. The natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois. The Partnership is controlled equally by CenterPoint Energy and OGE Energy, who each have 50% of the management rights of Enable GP. Enable GP was established by CenterPoint Energy and OGE Energy to govern the Partnership and has no other operating activities. Enable GP is governed by a board made up of an equal number of representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership's Chief Executive Officer and the independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. Based on the 50/50 management ownership, with neither company having control, effective May 1, 2013, CenterPoint Energy and OGE Energy deconsolidated their interests in the Partnership and Enogex, respectively. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP. At December 31, 2014, CenterPoint Energy held approximately 55.4% of the limited partner interests in the Partnership, or 94,126,366 common units and 139,704,916 subordinated units, and OGE Energy held approximately 26.3% of the limited partner interests in the Partnership, or 42,832,291 common units and 68,150,514 subordinated units. The limited partner interests of the Partnership have limited voting rights on matters affecting the business. As such, limited partners do not have rights to elect the Partnership’s General Partner (Enable GP) on an annual or continuing basis and may not remove Enable GP without at least a 75% vote by all unitholders, including all units held by the Partnership’s limited partners, and Enable GP and its affiliates, voting together as a single class. Upon conversion to a limited partnership on May 1, 2013, the Partnership’s earnings are generally no longer subject to income tax (other than Texas state margin taxes and taxes associated with the Partnership's corporate subsidiary) and are taxable at the individual partner level. As a result of the conversion to a partnership immediately prior to formation, CenterPoint Energy assumed all outstanding current income tax liabilities and the Partnership derecognized the deferred income tax assets and liabilities by recording an income tax benefit of $1.24 billion. Consequently, the Combined and Consolidated Statements of Income do not include an income tax provision on income earned on or after May 1, 2013 (other than Texas state margin taxes and taxes associated with the Partnership's corporate subsidiary). See Note 15 for further discussion of the Partnership’s income taxes. Prior to May 1, 2013, the financial statements of the Partnership include EGT, MRT and the non-rate regulated natural gas gathering, processing and treating operations, which were under common control by CenterPoint Energy, and a 50% interest in SESH. Through the Partnership's formation on May 1, 2013, CenterPoint Energy retained certain assets and liabilities and related balances in accumulated other comprehensive loss, historically held by the Partnership, such as certain notes payable—affiliated companies to CenterPoint Energy and benefit plan obligations. Additionally, the Partnership distributed a 25.05% interest in SESH to CenterPoint Energy, subject to future acquisition by the Partnership through put and call options discussed in Note 9. On May 1, 2013, OGE Energy and ArcLight indirectly contributed 100% of the equity interests in Enogex to the Partnership in exchange for limited partner interests and, for OGE Energy only, interests in Enable GP. The Partnership concluded that the Partnership formation on May 1, 2013 was considered a business combination, and for accounting purposes, the Partnership was the acquirer of Enogex. Subsequent to May 1, 2013, the financial statements of the Partnership are consolidated to reflect the formation of the Partnership and the acquisition of Enogex. See Note 3 for further discussion of the acquisition of Enogex. For the period from May 1, 2013 through May 29, 2014, the financial statements reflect a 24.95% interest in SESH. For the period of May 30, 2014 through December 31, 2014, the financial statements reflect a 49.90% interest in SESH. See Note 9 for further discussion of SESH. In addition, at December 31, 2014, as a result of the acquisition of Enogex on May 1, 2013, the Partnership held a 50% ownership interest in Atoka Midstream LLC (Atoka). At December 31, 2014, the Partnership consolidated Atoka in its Combined and Consolidated Financial Statements as Enable Oklahoma acted as the managing member of Atoka and had control over the operations of Atoka. On April 16, 2014, the Partnership completed the Offering of 25,000,000 common units, representing limited partner interests in the Partnership, at a price to the public of $20.00 per common unit. The Partnership received net proceeds of $464 million from the sale of the common units, after deducting underwriting discounts and commissions, the structuring fee and offering expenses. In connection with the Offering, underwriters exercised their option to purchase 3,750,000 additional common units, which were fulfilled with units held by ArcLight. As a result, the Partnership did not receive any proceeds from the sale of common units pursuant to the exercise of the underwriters' option to purchase additional common units. The exercise of the underwriters' option to purchase additional common units did not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all outstanding units. The Partnership retained the net proceeds of the Offering for general partnership purposes, including the funding of expansion capital expenditures, and to pre-fund demand fees expected to be incurred over the next three years relating to certain expiring transportation and storage contracts. In connection with the Offering, 139,704,916 of CenterPoint Energy's common units and 68,150,514 of OGE Energy's common units were converted into subordinated units.
Basis of Presentation	Basis of Presentation The accompanying combined and consolidated financial statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP. For accounting and financial reporting purposes, (i) the formation of the Partnership is considered a contribution of real estate by CenterPoint Energy and is reflected at CenterPoint Energy’s historical cost as of May 1, 2013 and (ii) the Partnership acquired Enogex on May 1, 2013. The combined and consolidated financial statements have been prepared from the historical accounting records maintained by CenterPoint Energy for the Partnership until May 1, 2013 and may not necessarily be indicative of the condition that would have existed or the results of operations if the Partnership had been operated as a separate and unaffiliated entity. All of the Partnership’s historical combined entities were under common control and management for the periods presented until May 1, 2013, and all intercompany transactions and balances are eliminated in combination and consolidation, as applicable. Beginning on May 1, 2013, the Partnership consolidated Enogex and all previously combined entities of the Partnership.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Revenues	Revenues Revenues for gathering, processing, transportation and storage services for the Partnership are recorded each month based on the current month’s estimated volumes, contracted prices (considering current commodity prices), historical seasonal fluctuations and any known adjustments. The estimates are reversed in the following month and customers are billed on actual volumes and contracted prices. Gas sales are calculated on current-month nominations and contracted prices. Revenues associated with the production of NGLs are estimated based on current-month estimated production and contracted prices. These amounts are reversed in the following month and the customers are billed on actual production and contracted prices. Estimated revenues are reflected in Accounts Receivable or Accounts Receivable-affiliated companies, as appropriate, on the Consolidated Balance Sheets and in Revenues on the Combined and Consolidated Statements of Income. The Partnership recognizes revenue from natural gas gathering, processing, transportation and storage and crude oil gathering services to third parties as services are provided. Revenue associated with NGLs is recognized when the production is sold. The partnership records deferred revenue when it receives consideration from a third party before achieving certain criteria that must be met for revenue to be recognized in accordance with GAAP. The Partnership has $18 million and $9 million of deferred revenues on the Consolidated Balance Sheets as of December 31, 2014 and 2013, respectively. The Partnership relies on certain key natural gas producer customers for a significant portion of natural gas and NGLs supply. The Partnership relies on certain key utilities for a significant portion of transportation and storage demand. The Partnership depends on third-party facilities to transport and fractionate NGLs that it delivers to third parties at the inlet of their facilities.
Natural Gas Purchases	Natural Gas Purchases Estimates for gas purchases are based on estimated volumes and contracted purchase prices. Estimated gas purchases are included in Accounts Payable or Accounts Payable-affiliated companies, as appropriate, on the Consolidated Balance Sheets and in Cost of Goods Sold, excluding Depreciation and Amortization on the Combined and Consolidated Statements of Income.
Environmental Costs	Environmental Costs The Partnership expenses or capitalizes environmental expenditures, as appropriate, depending on their future economic benefit. The Partnership expenses amounts that relate to an existing condition caused by past operations that do not have future economic benefit. The Partnership records undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.
Depreciation and Amortization	Depreciation and Amortization Expense Depreciation is computed using the straight-line method based on economic lives or a regulatory-mandated recovery period. Amortization of intangible assets is computed using the straight-line method over the respective lives of the intangible assets. The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets at the time the assets are placed in service. As circumstances warrant, useful lives are adjusted when changes in planned use, changes in estimated production lives of affiliated natural gas basins or other factors indicate that a different life would be more appropriate. Such changes could materially impact future depreciation expense. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively. The computation of amortization expense on intangible assets requires judgment regarding the amortization method used. Intangible assets are amortized on a straight-line basis over their useful lives using a method of amortization that reflects the pattern in which the economic benefits of the intangible asset are consumed.
Income Taxes	Income Taxes Prior to May 1, 2013, the Partnership was included in the consolidated income tax returns of CenterPoint Energy. The Partnership calculated its income tax provision on a separate return basis under a tax sharing agreement with CenterPoint Energy. The Partnership used 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 were 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 was established against deferred tax assets for which management believed realization was not considered more likely than not. Current federal and certain state income taxes were payable to or receivable from CenterPoint Energy. The Partnership recognized interest and penalties as a component of income tax expense. Upon conversion to a limited partnership on May 1, 2013, the Partnership’s earnings are no longer subject to income tax (other than Texas state margin taxes and taxes associated with the Partnership's corporate subsidiary) and are taxable at the individual partner level.
Cash and Cash Equivalents	Cash and Cash Equivalents The Partnership considers cash equivalents to be short-term, highly liquid investments with maturities of three months or less from the date of purchase.
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.
Inventory	Inventory Materials and supplies inventory is valued at cost and is subsequently recorded at the lower of cost or market. During the years ended December 31, 2014 and 2013, the Partnership recorded write-downs to market value related to materials and supplies inventory disposed or identified as excess or obsolete of $9 million and $2 million, respectively. No such write-down was recorded in the year ended December 31, 2012. Materials and supplies are recorded to inventory when purchased and, as appropriate, subsequently charged to operation and maintenance expense on the Combined and Consolidated Statements of Income or capitalized to property, plant and equipment on the Consolidated Balance Sheets when installed. Natural gas inventory is held, through the Transportation and Storage segment, to provide operational support for the intrastate pipeline deliveries and to manage leased intrastate storage capacity. Natural gas liquids inventory is held, through the Gathering and Processing segment, due to timing differences between the production of certain natural gas liquids and ultimate sale to third parties. Natural gas and natural gas liquids inventory is valued using moving average cost and is subsequently recorded at the lower of cost or market.
Gas Imbalances	Gas Imbalances Gas imbalances occur when the actual amounts of natural gas delivered from or received by the Partnership’s pipeline system differ from the amounts scheduled to be delivered or received. Imbalances are due to or due from shippers and operators and can be settled in cash or made up in-kind depending on contractual terms. The Partnership values all imbalances at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value.
Long-Lived Assets (including Intangible Assets)	Long-Lived Assets (including Intangible Assets) The Partnership records property, plant and equipment and intangible assets at historical cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and capitalized interest. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances and charged to Accumulated Depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation and the remaining balance net of any salvage proceeds is recorded as a loss in the Consolidated Statements of Income as Operation and Maintenance Expense. The Partnership expenses repair and maintenance costs as incurred. Repair, removal and maintenance costs are included in the Consolidated Statements of Income as Operation and Maintenance Expense. Assessing Impairment of Long-lived Assets (including Intangible Assets) and Goodwill The Partnership periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles other than goodwill, 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, as compared to the carrying value of the assets. The Partnership assesses its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. The Partnership tested its goodwill for impairment on May 1, 2013 upon formation and following formation tests annually on October 1. The Partnership utilizes the market or income approaches to estimate the fair value of the reporting unit, also giving consideration to the alternative cost approach. Under the market approach, historical and current year forecasted cash flows are multiplied by a market multiple to determine fair value. Under the income approach, anticipated cash flows over a period of years plus a terminal value are discounted to present value using appropriate discount rates. 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. The Partnership performs its goodwill impairment testing one level below the Transportation and Storage and Gathering and Processing segment level at the operating segment level.
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities The Partnership applies the guidance for accounting for regulated operations to portions of the Transportation and Storage segment. The Partnership’s rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment.
Capitalization of Interest and Allowance for Funds Used During Construction	Capitalization of Interest and Allowance for Funds Used During Construction Allowance for funds used during construction (AFUDC) represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases both utility plant and earnings, it is realized in cash when the assets are included in rates for combined entities that apply guidance for accounting for regulated operations. Capitalized interest represents the approximate net composite interest cost of borrowed funds used for construction. Interest and AFUDC are capitalized as a component of projects under construction and will be amortized over the assets’ estimated useful lives.
Derivative Instruments	Derivative Instruments The Partnership is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. At times, the Partnership utilizes derivative instruments such as physical forward contracts, financial futures and swaps to mitigate the impact of changes in commodity prices on its operating results and cash flows. Such derivatives are recognized in the Partnership’s Combined or Consolidated Balance Sheets at their fair value unless the Partnership elects hedge accounting or 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. The Partnership’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.
Fair Value Measurements	Fair Value Measurements The Partnership determines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As required, the Partnership utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy included in current accounting guidance. The Partnership generally applies the market approach to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Inventory

The cost of gas associated with sales of natural gas and natural gas liquids inventory is presented in Cost of goods sold, excluding depreciation and amortization on the Combined and Consolidated Statements of Income.



	December 31,
	2014		2013
	(In millions)
Materials and supplies	$	39	$	60
Natural gas and natural gas liquids inventories	24		23
Total	$	63	$	83

Acquisition of Enogex (Tables)

12 Months Ended

Dec. 31, 2014

Business Combinations [Abstract]

Schedule of Assets Acquired and Liabilities Assumed



	Amounts Recognized as of May 1, 2013
	(In millions)
Assets
Current Assets	$	192
Property, plant and equipment	3,919
Goodwill	439
Other intangible assets	401
Other assets	21
Total assets	$	4,972

Liabilities
Current liabilities	$	393
Long-term debt	745
Other liabilities	20
Total liabilities	1,158
Less: Noncontrolling interest at fair value	26
Fair value of consideration transferred	$	3,788

Pro Forma Information



Revenues	$	1,406
Operating income	92
Net income	77
Net income attributable to Enable Midstream Partners, LP	74

The Partnership’s pro forma results of operations in the combined entity had the acquisition of Enogex been completed on January 1, 2012 are as follows:



	Year ended December 31,
	2013		2012
	(In millions)
Unaudited pro forma results of operations:
Pro forma revenues	$	3,120	$	2,563
Pro forma operating income	487		558
Pro forma net income	1,638		433
Pro forma net income attributable to Enable Midstream Partners, LP	1,635		431

Earnings Per Limited Partner Unit (Tables)

12 Months Ended

Dec. 31, 2014

Earnings Per Share [Abstract]

Schedule Of Earnings Per Unit For Common And Subordinated Limited Partner Units [Table Text Block]

The following table illustrates the Partnership’s calculation of earnings per unit for common and subordinated limited partner units:



	Year Ended December 31,
	2014		2013		2012
	(In millions, except per unit data)
Net income attributable to Enable Midstream Partners, LP	$	530	$	1,615	$	316
Less general partner interest in net income	—		—		—
Limited partner interest in net income attributable to Enable Midstream Partners, LP	$	530	$	1,615	$	316
Net income allocable to common units	$	339	$	289	$	—
Net income allocable to subordinated units	191		—		—
Limited partner interest in net income attributable to Enable Midstream Partners, LP	$	530	$	289	$	—
Basic and diluted weighted average number of outstanding limited partner units
Common units	264		390		—
Subordinated units	148		—		—
Total	412		390		—
Basic and diluted earnings per limited partner unit
Common units	$	1.29	$	0.74	$	—
Subordinated units	$	1.28	$	—	$	—

Enable Midstream Partners, LP Parent Net Equity and Partners' Capital (Tables)

12 Months Ended

Dec. 31, 2014

Equity [Abstract]

Schedule Of Equity Transactions With Limited Partner

On April 30, 2013, immediately prior to formation of the limited partnership, while under common control, CenterPoint Energy completed equity transactions with the Partnership, whereby CenterPoint Energy made a cash contribution to the Partnership and retained certain assets and liabilities previously held by the Partnership, all of which were deemed to be transfers of net assets not constituting a transfer of a business, as follows:



	Amounts retained prior to May 1, 2013
	(In millions)
Contributions from (Distributions to) CenterPoint Energy
Cash	$	40
Pension and postretirement plans	22
Deferred financing cost	6
Investment in 25.05% of SESH (see Note 9)	(197		)
Increase in Notes payable-affiliated companies	(143		)
Decrease in Notes receivable-affiliated companies	(45		)
Income tax obligations, net	28
Net distributions to CenterPoint Energy prior to formation	$	(289	)

Quarter Ended

Record Date

Payment Date

Per Unit Distribution

Total Cash Distribution

June 30, 2014 ⁽¹⁾

August 4, 2014

August 14, 2014

0.2464

104

September 30, 2014

November 4, 2014

November 14, 2014

0.3025

128

December 31, 2014

February 4, 2015

February 13, 2015

0.30875

130

_____________________


(1)	The quarterly distribution for three months ended June 30, 2014 was prorated for the period beginning immediately after the closing of the Partnership's Offering, April 16, 2014 through June 30, 2014.

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2014

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, plant and equipment includes the following:



	Weighted Average Useful Lives (Years)	December 31,
	Weighted Average Useful Lives (Years)	2014		2013
		(In millions)
Property, plant and equipment, gross:
Gathering and Processing	35	$	5,560	$	5,123
Transportation and Storage	37	4,300		4,300
Construction work-in-progress		604		232
Total		$	10,464	$	9,655
Accumulated depreciation:
Gathering and Processing		343		213
Transportation and Storage		539		452
Total accumulated depreciation		882		665
Property, plant and equipment, net		$	9,582	$	8,990

Intangible Assets, Net (Tables)

12 Months Ended

Dec. 31, 2014

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Finite-Lived Intangible Assets

Intangible assets by intangible asset class are as follows as of December 31, 2014:



	Acquisition of Enogex		Accumulated Amortization		Net Intangible Assets
	(In millions)
Customer relationships	$	401	$	45	$	356
Total	$	401	$	45	$	356

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense

The following table summarizes the Partnership's expected amortization of intangible assets for each of the next five years:



	2015		2016		2017		2018		2019
	(In millions)
Expected amortization of intangible assets	$	27	$	27	$	27	$	27	$	27

Goodwill (Tables)

12 Months Ended

Dec. 31, 2014

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

Goodwill by reportable segment is as follows:



	December 31, 2012		Acquisition of Enogex⁽¹⁾		December 31, 2013		December 31, 2014
	(In millions)
Gathering and Processing	$	50	$	439	$	489	$	489
Transportation and Storage	579		—		579		579
Total	$	629	$	439	$	1,068	$	1,068

__________________________


(1)	See Note 3 for further discussion regarding the acquisition of Enogex.

Investment in Equity Method Affiliates (Tables)

12 Months Ended

Dec. 31, 2014

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Investments Detail

Investment in Equity Method Affiliates:



	(In millions)
Balance as of December 31, 2012	$	405
Distributions to CenterPoint Energy	(196		)
Equity in earnings of equity method affiliate	15
Capitalized interest on investment in SESH	(2		)
Distributions from equity method affiliate	(24		)
Balance as of December 31, 2013	198
Interest acquisition of SESH	161
Return of investment from SESH refinancing	(198		)
Additional investment in SESH	187
Equity in earnings of equity method affiliate	20
Contributions to equity method affiliate	3
Distributions from equity method affiliate	(23		)
Balance as of December 31, 2014	$	348

Equity in Earnings of Equity Method Affiliates:



	Year Ended December 31,
	2014		2013		2012
	(In millions)
Waskom	$	—	$	—	$	5
SESH	20		15		26
Total	$	20	$	15	$	31

Distributions from Equity Method Affiliates:



	Year Ended December 31,
	2014		2013		2012
	(In millions)
Waskom	$	—	$	—	$	7
SESH ⁽¹⁾	$	23	$	24	$	32

_____________________


(1)	Excludes $198 million in special distributions for the return of investment in SESH for the year ended December 31, 2014.

Summarized financial information of SESH is presented below:



	December 31,
	2014			2013
	(In millions)
Balance Sheets:
Current assets	$	57		$	53
Property, plant and equipment, net	1,127			1,132
Other assets	3			—
Total assets	$	1,187		$	1,185
Current liabilities	$	19		$	20
Long-term debt	400			375
Members’ equity	768			790
Total liabilities and members’ equity	$	1,187		$	1,185
Reconciliation:
Investment in SESH	$	348		$	198
Less: Capitalized interest on investment in SESH	(2		)	(1		)
The Partnership’s share of members' equity	$	346		$	197



	Year Ended December 31,
	2014		2013		2012
	(In millions)
Income Statements:
Revenues	$	108	$	107	$	110
Operating income	69		66		71
Net income	48		47		52

Debt (Tables)

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Schedule of Debt

The following table presents the Partnership's outstanding debt as of December 31, 2014 and 2013.



	December 31,
	2014		2013
	(In millions)
Revolving Credit Facility	$	—	$	333
Commercial Paper	253		—
Term Loan Facility	—		1,050
Enable Oklahoma Term Loan	—		250
2019 Notes	500		—
2024 Notes	600		—
2044 Notes	550		—
Enable Oklahoma Senior Notes	250		450
Premium on Enable Oklahoma Senior Notes	28		37
Total debt	2,181		2,120
Less amount classified as short-term debt⁽¹⁾	253		204
Total long-term debt	$	1,928	$	1,916

Schedule of Maturities of Long-term Debt

Maturities of long-term debt, excluding unamortized premiums, are as follows:



	Long-term debt
	(In millions)
2015	$	—
2016	—
2017	—
2018	—
2019	500
Thereafter	1,400

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Schedule of Fair Value and Carrying Amount of Financial Instruments

The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments at December 31, 2014 and December 31, 2013.



	December 31, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-Term Debt
Long-term notes payable - affiliated companies (Level 2)	$	363	$	362	$	363	$	363
Revolving Credit Facility (Level 2)⁽¹⁾	—		—		333		333
Term Loan Facility (Level 2)	—		—		1,050		1,050
Enable Oklahoma Term Loan (Level 2)	—		—		250		250
Enable Oklahoma Senior Notes (Level 2)⁽²⁾	279		282		487		477
Enable Midstream Partners, LP, 2019, 2024 and 2044 Notes (Level 2)	1,649		1,592		—		—

___________________


(1)	Borrowing capacity is reduced by our borrowings outstanding under the commercial paper program. $253 million of commercial paper was outstanding as of December 31, 2014, and no amount was outstanding as of December 31, 2013.


(2)	No amount is included in the current portion of long term debt as of December 31, 2014, and $204 million is included as of December 31, 2013.

Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables summarize the Partnership’s assets and liabilities that are measured at fair value on a recurring basis at December 31, 2014 and December 31, 2013:



December 31, 2014	Commodity Contracts						Gas Imbalances ⁽¹⁾
	Assets			Liabilities			Assets ⁽²⁾		Liabilities ⁽³⁾
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	33		$	4		$	—	$	—
Significant other observable inputs (Level 2)	2			—			40		$	12
Unobservable inputs (Level 3)	5			—			—		$	—
Total fair value	40			4			40		$	12
Netting adjustments	(4		)	(4		)	—		$	—
Total	$	36		$	—		$	40	$	12



December 31, 2013	Commodity Contracts						Gas Imbalances ⁽¹⁾
	Assets			Liabilities			Assets ⁽²⁾		Liabilities ⁽³⁾
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	1		$	2		$	—	$	—
Significant other observable inputs (Level 2)	—			1			8		10
Total fair value	1			3			8		10
Netting adjustments	(1		)	(2		)	—		—
Total	$	—		$	1		$	8	$	10

______________________

(1)


(2)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $4 million and $2 million at December 31, 2014 and December 31, 2013, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.


(3)	Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1 million and $3 million at December 31, 2014 and December 31, 2013, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

As of December 31, 2014, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes.



	Gross Notional Volume
	Purchases	Sales
Natural gas—TBtu⁽¹⁾
Physical	4	32
Fixed futures/swaps	5	35
Basis futures/swaps	7	54
Condensate—MBbl⁽²⁾
Futures/swaps	—	12

____________________


(1)	91.2 percent of the natural gas contracts have durations of one year or less, 6.5 percent have durations of more than one year and less than two years and 2.2 percent have durations of more than two years.


(2)	100.0 percent of the condensate contracts have durations of one year or less.

As of December 31, 2013, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes.



	Gross Notional Volume
	Purchases	Sales
Natural gas—TBtu⁽¹⁾
Physical	7	43
Fixed futures/swaps	3	5
Basis futures/swaps	3	6

____________________


(1)	94.8 percent of the natural gas contracts have durations of one year or less, 2.5 percent have durations of more than one year and less than two years and 2.7 percent have durations of more than two years.

Schedule of Derivative Assets at Fair Value

The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheet at December 31, 2014 are as follows:



		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities
		(In millions)
Derivatives not designated as hedging instruments
Natural gas
Financial futures/swaps	Other Current	$	34	$	4
Physical purchases/sales	Other Current	1		—
Condensate
Financial futures/swaps	Other Current	5		—
Total gross derivatives ⁽¹⁾		$	40	$	4

_____________________


(1)	See Note 11 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheet as of December 31, 2014.

The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheet at December 31, 2013 are as follows:



		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities
		(In millions)
Derivatives not designated as hedging instruments
Natural gas
Financial futures/swaps	Other Current	$	1	$	2
Physical purchases/sales	Other Current	—		1
Total gross derivatives ⁽¹⁾		$	1	$	3

_______________________


(1)	See Note 11 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheet as of December 31, 2013.

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

The following tables present the effect of derivative instruments on the Partnership’s Consolidated Statement of Income.



	Amounts Recognized in Income
	Year Ended December 31,
	2014		2013			2012
	(In millions)
Natural gas physical purchases/sales gains (losses)	$	1	$	—		$	—
Natural gas financial futures/swaps gains (losses)	37		(1		)	—
NGL/Condensate financial futures/swaps gains (losses)	11		—			—
Total	$	49	$	(1	)	$	—

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=35706170&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=35706170&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 815
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-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5580258-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5579245-113959

Reference 7: 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=35706170&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5579240-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=35706170&loc=d3e41620-113959

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2014

Schedule of Revenues from Related Parties

Amounts of revenues from affiliated companies included in the Partnership’s Combined and Consolidated Statements of Income are summarized as follows:



	Year Ended December 31,
	2014		2013		2012
	(In millions)
Gas transportation and storage — CenterPoint Energy	$	112	$	108	$	133
Gas sales — CenterPoint Energy	22		70		—
Gas transportation and storage — OGE Energy ⁽¹⁾	39		32		—
Gas sales — OGE Energy⁽¹⁾	13		14		—
Total revenues — affiliated companies	$	186	$	224	$	133

____________________

(1)

Schedule of Natural Gas Purchased From Related Parties

Amounts of natural gas purchased from affiliated companies included in the Partnership’s Combined and Consolidated Statements of Income are summarized as follows:



	Year Ended December 31,
	2014		2013		2012
	(In millions)
Cost of goods sold — CenterPoint Energy	$	2	$	4	$	1
Cost of goods sold — OGE Energy	19		8		—
Total cost of goods sold — affiliated companies	$	21	$	12	$	1

Schedule of Amounts Charged to Partnership by Related Parties



	Year Ended December 31,
	2014		2013		2012
	(In millions)
Seconded Employee Costs - CenterPoint Energy ⁽¹⁾	$	138	$	92	$	—
Corporate Services - CenterPoint Energy	29		38		39
Seconded Employee Costs - OGE Energy ⁽²⁾	105		78		—
Corporate Services - OGE Energy ⁽²⁾	17		18		—
Total corporate services and seconded employees expense	$	289	$	226	$	39

_________________________


(1)	Beginning on May 1, 2013, CenterPoint Energy assumed all employees of the Partnership and seconded such employees to the Partnership. Therefore, costs historically incurred directly by the Partnership for employment services are reflected as seconded employee costs subsequent to formation on May 1, 2013.


(2)	Corporate services and seconded employee expenses from OGE Energy are reflected in the Combined and Consolidated Statement of Income beginning on May 1, 2013.

Commitments and Contingencies Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Schedule of Future Minimum Rental Payments for Operating Leases

Operating Lease Obligations. The Partnership has operating lease obligations expiring at various dates. Future minimum payments for noncancellable operating leases are as follows:



	Year Ended December 31,
	2015		2016		2017		2018		2019		After 2019		Total
	(In millions)
Noncancellable operating leases	$	12	$	7	$	3	$	3	$	1	$	—	$	26

Other Commitments

The Partnership’s other future purchase obligations and commitments estimated for the next five years are as follows:



	Year Ended December 31,
	2015		2016		2017		2018		2019		Total
	(In millions)
Other purchase obligations and commitments	$	5	$	1	$	—	$	—	$	—	$	6

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

The components of Deferred Income Taxes as of December 31, 2014 and 2013 were as follows:



	December 31,
	2014		2013
	(In millions)
Deferred tax assets:	$	—	$	—
Deferred tax liabilities:
Non-current:
Depreciation	9		8
Total non-current deferred tax liabilities	9		8
Accumulated deferred income taxes, net	$	9	$	8

Schedule of Components of Income Tax Expense (Benefit)

The items comprising income tax expense are as follows:



	Year Ended December 31,
	2014		2013			2012
	(In millions)
Provision (benefit) for current income taxes
Federal	$	—	$	1		$	6
State	1		1			1
Total provision (benefit) for current income taxes	1		2			7
Provision (benefit) for deferred income taxes, net
Federal	$	—	(1,039		)	$	164
State	1		(155		)	32
Total provision (benefit) for deferred income taxes, net	1		(1,194		)	196
Total income tax expense (benefit)	$	2	$	(1,192	)	$	203

Schedule of Effective Income Tax Rate Reconciliation

The following schedule reconciles the statutory Federal income tax rate to the effective income tax rate:



	Year Ended December 31,
	2014			2013			2012
	(In millions)
Income before income taxes	$	535		$	426		$	519
Federal statutory rate	—		%	35		%	35		%
Expected federal income tax expense	—			149			182
Increase in tax expense resulting from:
State income taxes, net of federal income tax	2			8			21
Income not subject to tax	—			(103		)	—
Conversion to partnership	—			(1,240		)	—
Other, net	—			(6		)	—
Total	2			(1,341		)	21
Total income tax expense (benefit)	$	2		$	(1,192	)	$	203
Effective tax rate	0.4		%	(275.9		)%	39.1		%

Schedule of Activity in Unrecognized Tax Benefits

The following table reconciles the beginning and ending balance of the Partnership’s unrecognized tax benefits:



	December 31,
	2014		2013		2012
	(In millions)
Balance, beginning of year	$	—	$	—	$	3
Tax Positions related to prior years:
Reductions	—		—		(3		)
Balance, end of year	$	—	$	—	$	—

Equity Based Compensation (Tables)

12 Months Ended

Dec. 31, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award

The following table summarizes the Partnership’s compensation expense for the years ended December 31, 2014, 2013, and 2012 related to performance units, restricted units, and phantom units.



	Year Ended December 31,
	2014		2013		2012
	(In millions)
Performance units	$	3	$	—	$	—
Restricted units	10		—
Phantom units	2		—		—
Total compensation expense	$	15	$	—	$	—

Schedule of Valuation Assumptions

The number of performance units granted based on total unitholder return and the assumptions used to calculate the grant date fair value of the performance units based on total unitholder return are shown in the following table.



	2014
Number of units granted	563,963
Fair value of units granted	$	26.12
Expected price volatility	22.2		%
Risk-free interest rate	0.83		%
Expected life of units (in years)	3.00

Restricted Units, Grants in Period And Grant Date Fair Value

The number of restricted units granted related to the Partnership’s employees and the grant date fair value are shown in the following table.



	2014
Restricted units granted on April 16, 2014 to the Chief Executive Officer and Chief Financial Officer of Enable GP	687,500
Fair value of restricted units granted	$	22.60

Restricted units granted to the Partnership's employees	304,901
Fair value of restricted units granted	$23.56 - $25.50

Phantom Units, Grants in Period And Grant Date Fair Value [Table Text Block]

The number of phantom units granted and the grant date fair value are shown in the following table.



	2014
Phantom units granted	106,718
Fair value of phantom units granted	$23.16 - $23.70

Schedule of Share-based Compensation, Activity

A summary of the activity for the Partnership's performance units, restricted units, and phantom units as of December 31, 2014 and changes in 2014 are shown in the following table.



	Performance Units				Restricted Stock				Phantom Units
	Number of Units		Aggregate Intrinsic Value		Number of Units		Aggregate Intrinsic Value		Number of Units		Aggregate Intrinsic Value
	(In millions, except unit data)
Units Outstanding at 12/31/2013	—				—				—
Granted⁽¹⁾	563,963				992,401				106,718
Vested	(1,545	)			(150,515	)			(500	)
Forfeited	(9,837	)			(3,818	)			(7,500	)
Units Outstanding at 12/31/2014	552,581		$	11	838,068		$	16	98,718		$	2
Units Fully Vested at 12/31/2014	1,545		$	—	150,515		$	—	500		$	—

Schedule of Unrecognized Compensation Cost, Nonvested Awards



	December 31, 2014
	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance Units	$	11	2.81
Restricted Units	13		1.89
Phantom Units	1		0.36
Total	$	25

Reportable Business Segments (Tables)

12 Months Ended

Dec. 31, 2014

Segment Reporting [Abstract]

Schedule of Financial Data for Business Segments and Services

Financial data for segments and services are as follows:



Year Ended December 31, 2014	Gathering and Processing ⁽¹⁾		Transportation and Storage ⁽²⁾		Eliminations			Total
	(In millions)
Revenues⁽³⁾	$	2,424	$	1,577	$	(634	)	$	3,367
Cost of goods sold, excluding depreciation and amortization	1,585		961		(632		)	1,914
Operation and maintenance	297		232		(2		)	527
Depreciation and amortization	160		116		—			276
Impairment	8		—		—			8
Taxes other than income tax	25		31		—			56
Operating income	$	349	$	237	$	—		$	586
Total assets	$	8,356	$	5,493	$	(2,012	)	$	11,837
Capital expenditures	$	740	$	103	$	(6	)	$	837



Year Ended December 31, 2013	Gathering and Processing ⁽¹⁾		Transportation and Storage ⁽²⁾		Eliminations			Total
	(In millions)
Revenues⁽³⁾	$	1,740	$	1,149	$	(400	)	$	2,489
Cost of goods sold, excluding depreciation and amortization	1,075		636		(398		)	1,313
Operation and maintenance	222		209		(2		)	429
Depreciation and amortization	117		95		—			212
Impairment	12		—		—			12
Taxes other than income tax	20		34		—			54
Operating income	$	294	$	175	$	—		$	469
Total assets	$	7,157	$	5,717	$	(1,642	)	$	11,232
Capital expenditures	$	431	$	142	$	—		$	573



Year Ended December 31, 2012	Gathering and Processing ⁽¹⁾		Transportation and Storage⁽²⁾		Eliminations			Total
	(In millions)
Revenues⁽³⁾	$	502	$	502	$	(52	)	$	952
Cost of goods sold, excluding depreciation and amortization	124		55		(50		)	129
Operation and maintenance	114		155		(2		)	267
Depreciation and amortization	50		56		—			106
Taxes other than income tax	5		29		—			34
Operating income	$	209	$	207	$	—		$	416
Total assets	$	2,439	$	4,052	$	(9	)	$	6,482
Capital expenditures	$	70	$	132	$	—		$	202

_____________________

(1)

(2)


(3)	The Partnership had no external customers accounting for 10% or more of revenues in periods shown. See Note 13 for revenues from affiliated companies.

Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

Summarized unaudited quarterly financial data for 2014 and 2013 are as follows:



	Quarters Ended
	March 31, 2014		June 30, 2014		September 30, 2014		December 31, 2014
	(in millions, except per unit data)
Revenues (including revenues from affiliates (Note 13))	$	1,002	$	827	$	803	$	735
Cost of Goods Sold, excluding depreciation and amortization (including expenses from affiliates (Note 13))	633		478		439		364
Operating income	162		138		152		134
Net income	150		121		139		123
Net income attributable to Enable Midstream Partners, LP	149		120		139		122

Basic and diluted earnings per common limited partner unit (Note 4)	$	0.38	$	0.29	$	0.33	$	0.29
Basic and diluted earnings per subordinated limited partner unit (Note 4)	$	—	$	0.29	$	0.33	$	0.29

	Quarters Ended
	March 31, 2013		June 30, 2013		September 30, 2013		December 31, 2013
	(in millions, except per unit data)
Revenues (including revenues from affiliates (Note 13))	$	261	$	612	$	792	$	824
Cost of Goods Sold, excluding depreciation and amortization (including expenses from affiliates (Note 13))	45		323		459		486
Operating income	108		116		115		130
Net income	59		1,338		105		116
Net income attributable to Enable Midstream Partners, LP	59		1,337		104		115

Basic and diluted earnings per common limited partner unit (Note 4)⁽¹⁾	$	—	$	0.18	$	0.27	$	0.29
Basic and diluted earnings per subordinated limited partner unit (Note 4)	$	—	$	—	$	—	$	—

____________________


(1)	Basic and diluted earnings per unit reflect net income attributable to the Partnership for periods subsequent to its formation as a limited partnership on May 1, 2013, as no limited partner units were outstanding prior to this date. See Note 4.

Summary of Significant Accounting Policies - Narrative (Details)				3 Months Ended								12 Months Ended			13 Months Ended
	Apr. 16, 2014 USD ($) $ / shares shares	Mar. 25, 2014	May 01, 2013 USD ($)	Dec. 31, 2014 USD ($) shares	Sep. 30, 2014 USD ($)	Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Sep. 30, 2013 USD ($)	Jun. 30, 2013 USD ($)	Mar. 31, 2013 USD ($)	Dec. 31, 2014 USD ($) shares	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	May 29, 2014	May 02, 2013	Apr. 30, 2013	Dec. 31, 2011 USD ($)
Minimum percentage of vote required by all unitholders												75.00%
Income tax benefit			$ 1,240,000,000									$ 2,000,000	$ (1,192,000,000)	$ 203,000,000
Deferred Revenue				$ 18,000,000				$ 9,000,000				18,000,000	9,000,000
Revenues				735,000,000	$ 803,000,000	$ 827,000,000	$ 1,002,000,000	824,000,000	$ 792,000,000	$ 612,000,000	$ 261,000,000	3,367,000,000	2,489,000,000	952,000,000
Environmental exit costs				0				0				0	0
Cash and cash equivalents				12,000,000				108,000,000				12,000,000	108,000,000	0				$ 0
Allowance for doubtful accounts receivable				0				0				0	0
Gain (Loss) on Sale of Assets and Asset Impairment Charges												0	(2,000,000)	0
Regulatory liabilities				$ 16,000,000				$ 16,000,000				16,000,000	16,000,000
Allowance for Funds Used During Construction, capitalized interest												$ 8,000,000	$ 7,000,000	$ 2,000,000
Conversion ratio		1.279082616
CenterPoint
Percentage share of management rights				50.00%								50.00%
Percentage share of incentive distribution rights				40.00%								40.00%
Limited partner ownership interest												55.40%
Income tax benefit												$ 1,240,000,000
OGE Energy
Percentage share of management rights				50.00%								50.00%
Percentage share of incentive distribution rights				60.00%								60.00%
Limited partner ownership interest												26.30%
Enogex
Ownership percentage																100.00%
Atoka
Limited partner ownership interest												50.00%
SESH
Limited partner ownership interest												49.90%
Ownership percentage				49.90%								49.90%					50.00%
Limited partner ownership interest, exercisable as early as May 2014					24.95%										24.95%
SESH \| CenterPoint
Distributed ownership percentage															25.05%
Common Units \| CenterPoint
Units outstanding \| shares				94,126,366								94,126,366
Common Units \| OGE Energy
Units outstanding \| shares				42,832,291								42,832,291
Subordinated Units \| CenterPoint
Units outstanding \| shares				139,704,916								139,704,916
Subordinated Units \| OGE Energy
Units outstanding \| shares				68,150,514								68,150,514
IPO \| Common Units
Common units issued during period (in shares) \| shares	25,000,000
Initial public offering price (in dollars per share) \| $ / shares	$ 20.00
Net proceeds from sale of common units, net of underwriting discounts, commissions, and other related expenses	$ 464,000,000
IPO \| Common Units \| CenterPoint
Conversion of stock, common units converted (in shares) \| shares	139,704,916
IPO \| Common Units \| OGE Energy
Conversion of stock, common units converted (in shares) \| shares	68,150,514
Over-Allotment Option \| Common Units
Common units issued during period (in shares) \| shares	3,750,000
Volume of natural gas liquids \| Customer Concentration Risk
Concentration risk percentage												21.00%	30.00%
Total revenue \| Customer Concentration Risk
Concentration risk percentage												7.00%	9.00%
Revenues												$ 235,000,000	$ 232,000,000
Other Revenue \| Customer Concentration Risk
Concentration risk percentage												0.00%	0.00%	0.00%
Materials and Supplies
Inventory Write-down												$ 9,000,000	$ 2,000,000	$ 0
Natural gas
Inventory Write-down												$ 4,000,000	$ 4,000,000	$ 0

Summary of Significant Accounting Policies - Inventory (Details) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Materials and supplies	$ 39	$ 60
Natural gas and natural gas liquids inventories	24	23
Total	$ 63	$ 83

Acquisition of Enogex - Schedule of Assets and Liabilities Assumed (Details) - USD ($) $ in Millions		3 Months Ended								4 Months Ended	8 Months Ended	12 Months Ended
	May 01, 2013	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Apr. 30, 2013	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Assets
Goodwill		$ 1,068				$ 1,068					$ 1,068	$ 1,068	$ 1,068	$ 629
Business Combination, Revenues And Net Income [Abstract]
Revenues		735	$ 803	$ 827	$ 1,002	824	$ 792	$ 612	$ 261			3,367	2,489	952
Operating income		134	152	138	162	130	115	116	108			586	469	416
Net income		$ 123	$ 139	$ 121	$ 150	$ 116	$ 105	$ 1,338	$ 59	$ 1,326	292	533	1,618	316
Net income attributable to Enable Midstream Partners, LP												$ 530	$ 1,615	$ 316
Enogex
Business Acquisition [Line Items]
Percentage of interest acquired	100.00%
Assets
Current Assets	$ 192
Property, plant and equipment	3,919
Goodwill	439
Other intangible assets	401
Other assets	21
Total assets	4,972
Liabilities
Current liabilities	393
Long-term debt	745
Other liabilities	20
Total liabilities	1,158
Less: Noncontrolling interest at fair value	26
Fair value of consideration transferred	$ 3,788
Business Combination, Revenues And Net Income [Abstract]
Revenues											1,406
Operating income											92
Net income											77
Net income attributable to Enable Midstream Partners, LP											$ 74
Weighted Average \| Enogex
Business Acquisition [Line Items]
Weighted Average Useful Lives (Years)												32 years
Common Units \| CenterPoint \| Partners' Capital
Business Acquisition [Line Items]
Units outstanding	227,508,825
Common Units \| OGE Energy \| Partners' Capital
Business Acquisition [Line Items]
Units outstanding	110,982,805
Common Units \| ArcLight \| Partners' Capital
Business Acquisition [Line Items]
Units outstanding	51,527,730

Acquisition of Enogex - Pro Forma Information (Details) - Enogex - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition [Line Items]
Pro forma revenues	$ 3,120	$ 2,563
Pro forma operating income	487	558
Pro forma net income	1,638	433
Pro forma net income attributable to Enable Midstream Partners, LP	$ 1,635	$ 431

Earnings Per Limited Partner Unit - Narrative (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Dilutive effect of unit-based awards (less than $0.01 per unit during the three and six months ended June 30, 2014)									$ 0.01
Net income attributable to Enable Midstream Partners, LP									$ 530	$ 1,615	$ 316
Less general partner interest in net income									0	0	0
Limited partner interest in net income attributable to Enable Midstream Partners, LP									530	1,615	316
Net income attributable to Enable Midstream Partners, LP	$ 122	$ 139	$ 120	$ 149	$ 115	$ 104	$ 1,337	$ 59	$ 530	$ 289	$ 0
Basic and diluted weighted average number of outstanding limited partner units
Basic and diluted weighted average number of outstanding limited partner units (in units)									412	390	0
Common Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income attributable to Enable Midstream Partners, LP									$ 339	$ 289	$ 0
Basic and diluted weighted average number of outstanding limited partner units
Basic and diluted weighted average number of outstanding limited partner units (in units)									264	390	0
Basic and diluted earnings per limited partner unit
Basic and diluted earnings per unit (in dollars per unit)	$ 0.29	$ 0.33	$ 0.29	$ 0.38	$ 0.29	$ 0.27	$ 0.18	$ 0.00	$ 1.29	$ 0.74	$ 0.00
Subordinated Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income attributable to Enable Midstream Partners, LP									$ 191	$ 0	$ 0
Basic and diluted weighted average number of outstanding limited partner units
Basic and diluted weighted average number of outstanding limited partner units (in units)									148	0	0
Basic and diluted earnings per limited partner unit
Basic and diluted earnings per unit (in dollars per unit)	$ 0.29	$ 0.33	$ 0.29	$ 0.00	$ 0.00	$ 0.00	$ 0.00	$ 0.00	$ 1.28	$ 0.00	$ 0.00

Enable Midstream Partners, LP Parent Net Equity and Partners' Capital - Contributions from (Distributions to) CenterPoint Energy (Details) - USD ($) $ in Millions							4 Months Ended	12 Months Ended			13 Months Ended
	Aug. 14, 2014	May 14, 2014	Feb. 14, 2014	Nov. 14, 2013	Aug. 14, 2013	Apr. 30, 2013	Apr. 30, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	May 29, 2014
Distribution Made to Limited Partner [Line Items]
Cash						$ 40
Pension and postretirement plans						22
Deferred financing cost						6
Increase in Notes payable-affiliated companies						(143)
Decrease in Notes receivable-affiliated companies						(45)		$ 0	$ (434)	$ 77
Income tax obligations, net						28
Net distributions to CenterPoint Energy prior to formation	$ (22)	$ (155)	$ (114)	$ (120)	$ (61)	(289)	$ (289)
SESH
Distribution Made to Limited Partner [Line Items]
Investment in 25.05% of SESH (see Note 9)						$ (197)
CenterPoint \| SESH
Distribution Made to Limited Partner [Line Items]
Distributed ownership percentage											25.05%

Enable Midstream Partners, LP Parent Net Equity and Partners' Capital - Cash Distributions (Details) - Cash Distribution [Member] - USD ($) $ / shares in Units, $ in Millions	Feb. 13, 2015	Nov. 14, 2014	Aug. 14, 2014
Distribution Made to Limited Partner [Line Items]
Per Unit Distribution, paid (in dollars per unit)		$ 0.3025	$ 0.2464
Distribution made to unitholders		$ 128	$ 104
Subsequent Event [Member]
Distribution Made to Limited Partner [Line Items]
Quarterly cash distribution declared (per common unit)	$ 0.30875
Total Cash Distribution, declared	$ 130

Enable Midstream Partners, LP Parent Net Equity and Partners' Capital - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions							4 Months Ended	12 Months Ended
	Aug. 14, 2014	May 14, 2014	Feb. 14, 2014	Nov. 14, 2013	Aug. 14, 2013	Apr. 30, 2013	Apr. 30, 2013	Dec. 31, 2014
Distribution Made to Limited Partner [Line Items]
Distribution to limited partner	$ 22	$ 155	$ 114	$ 120	$ 61	$ 289	$ 289
Limited partners' capital account, required quarterly distribution period								45 days
Minimum quarterly distribution per common unit								$ 0.2875
Incentive distribution, distribution per unit								$ 0.330625
Limited partners capital account, minimum quarterly distribution, annualized								150.00%
Distribution Subordination Period 1
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, minimum annualized quarterly distribution per unit								$ 1.15
Distribution Subordination Period 2
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, maximum annualized quarterly distribution per unit								$ 1.725
Maximum
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, incentive distribution rights, percentage								50.00%

Property, Plant and Equipment - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 10,464	$ 9,655
Less accumulated depreciation and amortization	882	665
Property, plant and equipment, net	9,582	8,990
Depreciation	$ 249	194	$ 106
Gathering and Processing
Property, Plant and Equipment [Line Items]
Weighted Average Useful Lives (Years)	35 years
Property, plant and equipment, gross	$ 5,560	5,123
Less accumulated depreciation and amortization	$ 343	213
Transportation and Storage
Property, Plant and Equipment [Line Items]
Weighted Average Useful Lives (Years)	37 years
Property, plant and equipment, gross	$ 4,300	4,300
Less accumulated depreciation and amortization	539	452
Construction work-in-progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 604	$ 232

Intangible Assets, Net - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Acquisition of Enogex	$ 401
Accumulated Amortization	45
Net Intangible Assets	356
Amortization of intangible assets	27	$ 18
Expected amortization of intangible assets, 2015	27
Expected amortization of intangible assets, 2016	27
Expected amortization of intangible assets, 2017	27
Expected amortization of intangible assets, 2018	27
Expected amortization of intangible assets, 2019	27
Customer Relationships
Finite-Lived Intangible Assets [Line Items]
Acquisition of Enogex	401
Accumulated Amortization	45
Net Intangible Assets	$ 356
Weighted average useful life	15 years

Goodwill - Narrative (Details) - USD ($)	12 Months Ended
Goodwill - Narrative (Details) - USD ($)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Goodwill [Roll Forward]
Goodwill	$ 1,068,000,000	$ 629,000,000
Acquisition of Enogex		439,000,000
Goodwill	1,068,000,000	1,068,000,000	$ 629,000,000
Goodwill impairment charge	0	0	0
Gathering and Processing
Goodwill [Roll Forward]
Goodwill	489,000,000	50,000,000
Acquisition of Enogex		439,000,000
Goodwill	489,000,000	489,000,000	50,000,000
Transportation and Storage
Goodwill [Roll Forward]
Goodwill	579,000,000	579,000,000
Acquisition of Enogex		0
Goodwill	$ 579,000,000	$ 579,000,000	$ 579,000,000

Investment in Equity Method Affiliates - Narrative (Details)												3 Months Ended	4 Months Ended	12 Months Ended			13 Months Ended
	Aug. 14, 2014 USD ($)	Jul. 25, 2014 USD ($)	Jun. 13, 2014 USD ($)	May 30, 2014 USD ($) shares	May 14, 2014 USD ($)	Feb. 14, 2014 USD ($)	Nov. 14, 2013 USD ($)	Aug. 14, 2013 USD ($)	May 01, 2013 shares	Apr. 30, 2013 USD ($) mi	Jul. 31, 2012 USD ($)	Sep. 30, 2014 USD ($)	Apr. 30, 2013 USD ($) mi	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	May 29, 2014	Aug. 01, 2012 USD ($)	Jun. 30, 2012
Distribution to limited partner	$ 22,000,000				$ 155,000,000	$ 114,000,000	$ 120,000,000	$ 61,000,000		$ 289,000,000			$ 289,000,000
Goodwill														$ 1,068,000,000	$ 1,068,000,000	$ 629,000,000
SESH
Interest contributed to the Partnership				24.95%
Limited partner units that may be issued, exercised \| shares				6,322,457
Limited partner interests in the Partnership, fair value				$ 161,000,000
Limited partner units that may be issued, exercisable as early as May 2015 \| shares									25,341
Limited partner ownership interest, exercisable as early as May 2015									0.10%
CenterPoint
Limited partner ownership interest														55.40%
CenterPoint
Distribution to limited partner												$ 1,000,000
Waskom
Distributions from unconsolidated affiliates														$ 0	0	7,000,000
Equity interest before remaining interest acquired, percentage																			50.00%
Additional interest acquired, value											$ 201,000,000
Equity interest before remaining interest acquired, fair value											201,000,000
Remeasurement gain											136,000,000
Additional goodwill resulting from remeasurement											8,000,000
SESH
Ownership percentage										50.00%			50.00%	49.90%
Interstate natural gas pipeline length (in miles) \| mi										286			286
Limited partner ownership interest, exercisable as early as May 2014												24.95%					24.95%
Limited partner ownership interest														49.90%
Distributions from unconsolidated affiliates														$ 23,000,000	24,000,000	$ 32,000,000
SESH \| CenterPoint
Distributed ownership percentage																	25.05%
Investments in Equity Method Affiliates \| SESH
Distributions from unconsolidated affiliates		$ 7,000,000	$ 198,000,000											23,000,000	24,000,000
Distribution to limited partner															$ 196,000,000
Investment in equity method investment														187,000,000
Investments in Equity Method Affiliates \| Senior Notes \| SESH
Face amount			400,000,000
Investments in Equity Method Affiliates \| Senior Notes Due August 2014 \| Senior Notes \| SESH
Face amount			$ 375,000,000
Return of Special Distribution [Member] \| Investments in Equity Method Affiliates \| SESH
Investment in equity method investment														$ (187,000,000)
Acquisition of Waskom and Other Gathering Assets
Payments to acquire additional interest and related assets											273,000,000
Property, plant and equipment acquired											253,000,000
Goodwill											$ 16,000,000							$ 24,000,000
Waskom Acquisition
Additional percentage acquired											50.00%
Goodwill																		17,000,000
Acquisition of Other Gathering Assets
Goodwill																		$ 7,000,000

Investment in Equity Method Affiliates - Schedule of Investments (Details) - USD ($) $ in Millions									3 Months Ended	4 Months Ended	12 Months Ended
	Aug. 14, 2014	Jul. 25, 2014	Jun. 13, 2014	May 14, 2014	Feb. 14, 2014	Nov. 14, 2013	Aug. 14, 2013	Apr. 30, 2013	Jun. 30, 2013	Apr. 30, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
Balance beginning of period											$ 198
Net distributions to CenterPoint Energy prior to formation	$ (22)			$ (155)	$ (114)	$ (120)	$ (61)	$ (289)		$ (289)
Equity in earnings of equity method affiliates											20	$ 15	$ 31
Interest acquisition of SESH											161	0	0
Return of investment from SESH refinancing											198	0	0
Contributions to equity method affiliate											464	43	0
Balance end of period											348	198
Equity in Earnings of Equity Method Affiliates:
Equity in earnings of equity method affiliates											20	15	31
Waskom
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
Distributions from unconsolidated affiliates											0	0	(7)
Distributions from Equity Method Affiliates:
Distributions from unconsolidated affiliates											0	0	(7)
SESH
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
Balance beginning of period											198
Distributions from unconsolidated affiliates											(23)	(24)	(32)
Balance end of period											348	198
Distributions from Equity Method Affiliates:
Distributions from unconsolidated affiliates											(23)	(24)	(32)
Operating revenues											108	107	110
Operating income											69	66	71
Net income											48	47	52
Other Income (Expense) \| Waskom
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
Equity in earnings of equity method affiliates											0	0	5
Equity in Earnings of Equity Method Affiliates:
Equity in earnings of equity method affiliates											0	0	5
Other Income (Expense) \| SESH
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
Equity in earnings of equity method affiliates									$ 4		20	15	26
Equity in Earnings of Equity Method Affiliates:
Equity in earnings of equity method affiliates									$ 4		20	15	26
Investments in Equity Method Affiliates \| SESH
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
Balance beginning of period										$ 405	198	405
Net distributions to CenterPoint Energy prior to formation												(196)
Equity in earnings of equity method affiliates											20	15
Capitalized interest on investment in SESH												(2)
Distributions from unconsolidated affiliates		$ (7)	$ (198)								(23)	(24)
Interest acquisition of SESH											161
Investment in equity method investment											187
Contributions to equity method affiliate											3
Balance end of period											348	198	$ 405
Equity in Earnings of Equity Method Affiliates:
Equity in earnings of equity method affiliates											20	15
Distributions from Equity Method Affiliates:
Distributions from unconsolidated affiliates		$ (7)	$ (198)								(23)	$ (24)
Special Distribution \| Investments in Equity Method Affiliates \| SESH
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
Return of investment from SESH refinancing											$ 198

Investment in Equity Method Affiliates - Financial Information of SESH (Details) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]
Investment in SESH	$ 348	$ 198
SESH
Schedule of Equity Method Investments [Line Items]
Current assets	57	53
Property, plant and equipment, net	1,127	1,132
Other assets	3	0
Total assets	1,187	1,185
Current liabilities	19	20
Long-term debt	400	375
Members’ equity	768	790
Total liabilities and members’ equity	1,187	1,185
Investment in SESH	348	198
Less: Capitalized interest on investment in SESH	(2)	(1)
The Partnership’s share of members' equity	$ 346	$ 197

Debt - Narrative (Details)			12 Months Ended
Debt - Narrative (Details)	May 27, 2014 USD ($)	May 01, 2013 USD ($)	Dec. 31, 2014 USD ($)	Jan. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Debt Instrument [Line Items]
Total debt			$ 2,181,000,000		$ 2,120,000,000
Unamortized premium					37,000,000
Less amount classified as short-term debt			253,000,000		204,000,000
Total long-term debt			1,928,000,000		1,916,000,000
Commercial paper, authorized				$ 1,400,000,000
Carrying value			253,000,000		0
Senior Notes
Debt Instrument [Line Items]
Proceeds from issuance of debt	$ 1,630,000,000
Senior Notes \| 2.400% Senior Notes
Debt Instrument [Line Items]
Total debt			500,000,000		0
Face amount	$ 500,000,000
Fixed interest rate	2.40%
Senior Notes \| 3.900% Senior Notes
Debt Instrument [Line Items]
Total debt			600,000,000		0
Face amount	$ 600,000,000
Fixed interest rate	3.90%
Senior Notes \| 5.000% Senior Notes
Debt Instrument [Line Items]
Total debt			550,000,000		0
Face amount	$ 550,000,000
Fixed interest rate	5.00%
Senior Notes \| 6.25% Senior Notes
Debt Instrument [Line Items]
Total debt			250,000,000		450,000,000
Unamortized premium			28,000,000		37,000,000
Face amount			$ 250,000,000
Fixed interest rate			6.25%
Effective percentage			5.60%
Senior Notes \| 6.875% Senior Notes
Debt Instrument [Line Items]
Face amount			$ 200,000,000
Fixed interest rate			6.875%
Commercial Paper [Member]
Debt Instrument [Line Items]
Total debt			$ 253,000,000		0
Term Loan Facility
Debt Instrument [Line Items]
Total debt			0		1,050,000,000
Maximum borrowing capacity		$ 1,050,000,000
Term loan facility, term		3 years
Losses on extinguishment of debt			4,000,000
Term Loan Facility \| Enable Oklahoma Term Loan
Debt Instrument [Line Items]
Total debt			$ 0		250,000,000
Maximum borrowing capacity		$ 250,000,000
Term Loan Facility \| LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate			1.625%
Revolving Credit Facility
Debt Instrument [Line Items]
Total debt			$ 0		333,000,000
Maximum borrowing capacity		$ 1,400,000,000
Letters of credit principal advances			0
Letters of credit outstanding amount			$ 2,000,000
Unused capacity, commitment fee percentage			0.25%
Consolidated debt to EBITDA ratio			5.00
Covenant, acceleration of indebtness, threshold amount			$ 100,000,000
Covenant, acceleration of indebtness, nonpayment of uninsured money judgments, threshold amount			100,000,000
Consideration transferred, threshold for debt covenant ratio			50,000,000
Other Assets
Debt Instrument [Line Items]
Unamortized debt expense			$ 17,000,000		$ 9,000,000
Maximum \| Revolving Credit Facility
Debt Instrument [Line Items]
Consolidated debt to EBITDA ratio			5.50

Debt - Maturities of Long Term Debt (Details) $ in Millions	Dec. 31, 2014 USD ($)
Debt Disclosure [Abstract]
Long-term debt maturities in 2015	$ 0
Long-term debt maturities in 2016	0
Long-term debt maturities in 2017	0
Long-term debt maturities in 2018	0
Long-term debt maturities in 2019	500
Thereafter	$ 1,400

Fair Value Measurements - Fair Value Hierarchy (Details) - USD ($)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fuel Reserves for Under Retained Fuel Due From Shippers	$ 4,000,000	$ 2,000,000
Fuel Reserves For Over Retained Fuel Due To Shippers	1,000,000	3,000,000
Asset impairment charges		12,000,000
Commodity Contracts \| Recurring Measurement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value, before netting adjustments	40,000,000	1,000,000
Derivative liability, fair value, before netting adjustments	4,000,000	3,000,000
Derivative asset, netting adjustment	(4,000,000)	(1,000,000)
Derivative liability, netting adjustment	(4,000,000)	(2,000,000)
Derivative Asset	36,000,000	0
Derivative Liability	0	1,000,000
Commodity Contracts \| Recurring Measurement \| Quoted market prices in active market for identical assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value, gross asset	33,000,000	1,000,000
Derivative asset, fair value, gross liability	4,000,000	2,000,000
Commodity Contracts \| Recurring Measurement \| Significant other observable inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value, gross asset	2,000,000	0
Derivative asset, fair value, gross liability	0	1,000,000
Commodity Contracts \| Recurring Measurement \| Unobservable inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value, gross asset	5,000,000
Derivative asset, fair value, gross liability	0
Gas Imbalances \| Recurring Measurement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value, before netting adjustments	40,000,000	8,000,000
Derivative liability, fair value, before netting adjustments	12,000,000	10,000,000
Derivative asset, netting adjustment	0	0
Derivative liability, netting adjustment	0	0
Derivative Asset	40,000,000	8,000,000
Derivative Liability	12,000,000	10,000,000
Gas Imbalances \| Recurring Measurement \| Quoted market prices in active market for identical assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value, gross asset	0	0
Derivative asset, fair value, gross liability	0	0
Gas Imbalances \| Recurring Measurement \| Significant other observable inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value, gross asset	40,000,000	8,000,000
Derivative asset, fair value, gross liability	12,000,000	10,000,000
Gas Imbalances \| Recurring Measurement \| Unobservable inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value, gross asset	0
Derivative asset, fair value, gross liability	0
Property, Plant and Equipment
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset impairment charges	$ 7,000,000	10,000,000
Materials and Supplies
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset impairment charges		$ 2,000,000

Fair Value Measurements - Carrying and Fair Value Amounts (Details) - USD ($)	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount	$ 2,181,000,000	$ 2,120,000,000
Carrying value	253,000,000	0
Short-term debt	253,000,000	204,000,000
Enable Oklahoma Senior Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term debt	0	204,000,000
Significant other observable inputs (Level 2) \| Long-term notes payable - affiliated companies (Level 2) \| Affiliated Companies
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value	362,000,000	363,000,000
Significant other observable inputs (Level 2) \| Revolving Credit Facility (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value	0	333,000,000
Significant other observable inputs (Level 2) \| Term Loan Facility (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value	0	1,050,000,000
Significant other observable inputs (Level 2) \| Enable Oklahoma Term Loan (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value	0	250,000,000
Significant other observable inputs (Level 2) \| Enable Oklahoma Senior Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value	282,000,000	477,000,000
Significant other observable inputs (Level 2) \| Enable Midstream Partners, LP, 2019, 2024 and 2044 Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value	1,592,000,000	0
Carrying Amount \| Significant other observable inputs (Level 2) \| Long-term notes payable - affiliated companies (Level 2) \| Affiliated Companies
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount	363,000,000	363,000,000
Carrying Amount \| Significant other observable inputs (Level 2) \| Revolving Credit Facility (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount	0	333,000,000
Carrying Amount \| Significant other observable inputs (Level 2) \| Term Loan Facility (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount	0	1,050,000,000
Carrying Amount \| Significant other observable inputs (Level 2) \| Enable Oklahoma Term Loan (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount	0	250,000,000
Carrying Amount \| Significant other observable inputs (Level 2) \| Enable Oklahoma Senior Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount	279,000,000	487,000,000
Carrying Amount \| Significant other observable inputs (Level 2) \| Enable Midstream Partners, LP, 2019, 2024 and 2044 Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount	$ 1,649,000,000	$ 0

Derivative Instruments and Hedging Activities - Narrative (Details)	12 Months Ended
	Dec. 31, 2014 USD ($) MMBTU MBbls	Dec. 31, 2013 USD ($) MMBTU
Derivative [Line Items]
Cash Flow Hedges Derivative Instruments at Fair Value, Net \| $	$ 0	$ 0
Fair value hedges \| $	$ 0	$ 0
Not Designated as Hedging Instrument \| Natural gas
Derivative [Line Items]
Percent of contract with durations of one year or less	91.20%	94.80%
Percent of contracts with durations of more than one year and less than two years	6.50%	2.50%
Percent of contracts having a duration of more than two years	2.20%	2.70%
Not Designated as Hedging Instrument \| Natural gas \| Physical \| Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	4,000,000	7,000,000
Not Designated as Hedging Instrument \| Natural gas \| Physical \| Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	32,000,000	43,000,000
Not Designated as Hedging Instrument \| Natural gas \| Fixed futures/swaps \| Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	5,000,000	3,000,000
Not Designated as Hedging Instrument \| Natural gas \| Fixed futures/swaps \| Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	35,000,000	5,000,000
Not Designated as Hedging Instrument \| Natural gas \| Basis futures/swaps \| Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	7,000,000	3,000,000
Not Designated as Hedging Instrument \| Natural gas \| Basis futures/swaps \| Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	54,000,000	6,000,000
Not Designated as Hedging Instrument \| Condensate
Derivative [Line Items]
Percent of contract with durations of one year or less	100.00%
Not Designated as Hedging Instrument \| Condensate \| Futures/swaps \| Purchases
Derivative [Line Items]
Derivative, gross notional volume (MMbl) \| MBbls	0
Not Designated as Hedging Instrument \| Condensate \| Futures/swaps \| Sales
Derivative [Line Items]
Derivative, gross notional volume (MMbl) \| MBbls	12

Derivative Instruments and Hedging Activities - Balance Sheet Location (Details) - Not Designated as Hedging Instrument - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013
Natural gas
Derivatives, Fair Value [Line Items]
Derivative Asset	$ 40
Derivative Liability	4
Natural gas \| Other Current
Derivatives, Fair Value [Line Items]
Derivative Asset		$ 1
Derivative Liability		3
Natural gas \| Financial futures/swaps \| Other Current
Derivatives, Fair Value [Line Items]
Derivative Asset	34	1
Derivative Liability	4	2
Natural gas \| Physical purchases/sales \| Other Current
Derivatives, Fair Value [Line Items]
Derivative Asset	1	0
Derivative Liability	0	$ 1
Condensate \| Financial futures/swaps \| Other Current
Derivatives, Fair Value [Line Items]
Derivative Asset	5
Derivative Liability	$ 0

Derivative Instruments and Hedging Activities - Amounts Recognized in Income (Details) - USD ($)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	$ 49,000,000	$ (1,000,000)	$ 0
Cash collateral required if ratings are lowered	0
Natural gas \| Physical purchases/sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	1,000,000	0	0
Natural gas \| Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	37,000,000	(1,000,000)	0
Condensate \| Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	$ 11,000,000	$ 0	$ 0

Related Party Transactions - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Partnership's revenues from affiliated companies as a percent of total revenues	6.00%	9.00%	14.00%
Charges to the Partnership by affiliates	$ 289,000,000	$ 226,000,000	$ 39,000,000
Notes payable—affiliated companies	363,000,000	363,000,000
Interest income—affiliated companies	0	9,000,000	21,000,000
CenterPoint
Related Party Transaction [Line Items]
Notes payable, related parties	363,000,000
Notes payable—affiliated companies		363,000,000
Affiliate interest expense	8,000,000	34,000,000	85,000,000
Interest income—affiliated companies	0	9,000,000	$ 21,000,000
CenterPoint \| 2.10% Note Payable
Related Party Transaction [Line Items]
Notes payable—affiliated companies	$ 273,000,000	$ 273,000,000
CenterPoint \| 2.10% Note Payable \| Long-term notes payable - affiliated companies (Level 2)
Related Party Transaction [Line Items]
Fixed interest rate	2.10%	2.10%
CenterPoint \| 2.45% Note Payable
Related Party Transaction [Line Items]
Notes payable—affiliated companies	$ 90,000,000	$ 90,000,000
CenterPoint \| 2.45% Note Payable \| Long-term notes payable - affiliated companies (Level 2)
Related Party Transaction [Line Items]
Fixed interest rate	2.45%	2.45%
CenterPoint \| Certain Services and Support Functions
Related Party Transaction [Line Items]
Expense reimbursement annual caps	$ 38,000,000
OGE Energy
Related Party Transaction [Line Items]
Period notice of termination prior to commencement of succeeding annual period	180 days
OGE Energy \| Defined Benefit And Retiree Medical Plans
Related Party Transaction [Line Items]
Expense reimbursement in 2015	$ 6,000,000
Expense reimbursement in 2016	6,000,000
Expense reimbursement in 2017	5,000,000
Expense reimbursement in 2018	5,000,000
Expense reimbursement, thereafter	5,000,000
OGE Energy \| Certain Services and Support Functions
Related Party Transaction [Line Items]
Expense reimbursement annual caps	$ 28,000,000
CenterPoint and OGE Energy
Related Party Transaction [Line Items]
Period notice of termination for reimbursements for all employee costs	90 days

Related Party Activity (Details) - USD ($) $ in Millions	12 Months Ended
Related Party Activity (Details) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Revenues from affiliated companies	$ 186	$ 224	$ 133
Cost of goods sold from affiliate	21	12	1
Charges to the Partnership by affiliates	289	226	39
CenterPoint
Related Party Transaction [Line Items]
Cost of goods sold from affiliate	2	4	1
CenterPoint \| Gas Transportation and Storage
Related Party Transaction [Line Items]
Revenues from affiliated companies	112	108	133
CenterPoint \| Gas Sales
Related Party Transaction [Line Items]
Revenues from affiliated companies	22	70	0
CenterPoint \| Seconded Employee Costs
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	138	92	0
CenterPoint \| Corporate Services
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	29	38	39
OGE Energy
Related Party Transaction [Line Items]
Cost of goods sold from affiliate	19	8	0
OGE Energy \| Gas Transportation and Storage
Related Party Transaction [Line Items]
Revenues from affiliated companies	39	32	0
OGE Energy \| Gas Sales
Related Party Transaction [Line Items]
Revenues from affiliated companies	13	14	0
OGE Energy \| Seconded Employee Costs
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	105	78	0
OGE Energy \| Corporate Services
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	$ 17	$ 18	$ 0

Commitments and Contingencies - Operating Leases Future Minimum Payments and Other Commitments (Details) $ in Millions	Dec. 31, 2014 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Noncancellable operating leases due in 2015	$ 12
Noncancellable operating leases due in 2016	7
Noncancellable operating leases due in 2017	3
Noncancellable operating leases due in 2018	3
Noncancellable operating leases due in 2019	1
Noncancellable operating leases due after 2019	0
Total	26
Other Commitments [Abstract]
Other purchase obligations and commitments due in 2015	5
Other purchase obligations and commitments due in 2016	1
Other purchase obligations and commitments due in 2017	0
Other purchase obligations and commitments due in 2018	0
Other purchase obligations and commitments due in 2019	0
Total	$ 6

Commitments and Contingencies - Narrative (Details) $ in Millions		12 Months Ended
	Mar. 01, 2007 MMBTU	Dec. 31, 2014 USD ($) ft² MMcf bbl agreement	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2006 MMcf	Dec. 31, 2004 USD ($) MMBTU
Long-term Purchase Commitment [Line Items]
Rent expense \| $		$ 23	$ 12	$ 16
Area of leased office space \| ft²		162,053
Office lease payments over the lease term \| $		$ 19
Office lease rent escalations increase period		5 years
Office lease rent escalations increase period if renewed		10 years
Number of compression service agreements		86
Number of compression service agreements on a month-to-month basis		36
Number of compression service agreements expiring in 2015		24
Number of compression service agreements expiring in 2016		20
Number of compression service agreements expiring in 2017		6
Number of gas treating agreements		8
Number of gas treating agreements on a month-to-month basis		7
Number of gas treating agreements expiring in 2015		1
Encana And Vine \| Gas Gathering and Processing Equipment
Long-term Purchase Commitment [Line Items]
Capacity per agreement \| MMcf		1,300
Long-term purchase commitment, amount \| $		$ 440
Midcontinental Express Pipeline
Long-term Purchase Commitment [Line Items]
Capacity per agreement \| MMcf					272
Firm capacity agreement term					10 years
Dunn and McKenzie Counties, North Dakota \| XTO
Long-term Purchase Commitment [Line Items]
Capacity per agreement \| bbl		19,500
Pipeline construction, expected cost remaining \| $		$ 53
Wyoming, Colorado and Kansas \| Cheyenne Plains Pipeline
Long-term Purchase Commitment [Line Items]
Capacity per agreement \| MMBTU						60,000
Transportation service agreement term						10 years
Transportation service agreement demand fee \| $						$ 7
Daily production, turned back \| MMBTU	20,000

Income Taxes - Schedule of Expense (Benefit) (Details) - USD ($) $ in Millions		12 Months Ended
	May 01, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Provision (benefit) for current income taxes
Federal		$ 0	$ 1	$ 6
State		1	1	1
Total provision (benefit) for current income taxes		1	2	7
Provision (benefit) for deferred income taxes, net
Federal		0	(1,039)	164
State		1	(155)	32
Total provision (benefit) for deferred income taxes, net		1	(1,194)	196
Total income tax expense (benefit)	$ 1,240	2	$ (1,192)	$ 203
CenterPoint
Provision (benefit) for deferred income taxes, net
Total income tax expense (benefit)		$ 1,240

Income Taxes - Effective Tax Rate Reconciliation (Details) - USD ($) $ in Millions		12 Months Ended
	May 01, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Income before income taxes		$ 535	$ 426	$ 519
Federal statutory rate		0.00%	35.00%	35.00%
Expected federal income tax expense		$ 0	$ 149	$ 182
State income taxes, net of federal income tax		2	8	21
Income not subject to tax		0	(103)	0
Conversion to partnership		0	(1,240)	0
Other, net		0	(6)	0
Total		2	(1,341)	21
Total income tax expense (benefit)	$ 1,240	$ 2	$ (1,192)	$ 203
Effective tax rate		0.40%	(275.90%)	39.10%

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Deferred tax assets	$ 0	$ 0
Deferred tax liabilities:
Depreciation	9	8
Total non-current deferred tax liabilities	9	8
Accumulated deferred income taxes, net	$ 9	$ 8

Income Taxes - Uncertain Tax Positions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance, beginning of year	$ 0	$ 0	$ 3
Reductions	0	0	(3)
Balance, end of year	$ 0	$ 0	$ 0

Equity Based Compensation - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions			12 Months Ended
	Jun. 02, 2014	Apr. 21, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense			$ 15.0	$ 0.0	$ 0.0
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense			$ 3.0	0.0	0.0
Units granted	563,963		563,963
Vesting period			3 years
Award cycle			3 years
Average volatility period			3 years
Fair value of units granted			$ 26.12
Expected price volatility			22.20%
Risk-free interest rate			0.83%
Expected life of units (in years)			3 years
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense			$ 10.0	0.0
Units granted			992,401
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense			$ 2.0	$ 0.0	$ 0.0
Units granted		106,718	106,718
Common Units \| Long Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units that may be delivered pursuant to vested awards			13,100,000

Equity Based Compensation - Restricted Units (Details) - $ / shares				12 Months Ended
	Jun. 02, 2014	Apr. 21, 2014	Apr. 16, 2014	Dec. 31, 2014
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted				992,401
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted		106,718		106,718
Chief Executive Officer \| Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period				4 years
Chief Executive Officer \| Restricted units \| Percentage Based Vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted			375,000
Chief Executive Officer \| Restricted units \| Equal Annual Based Vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted			150,000
Chief Executive Officer \| Restricted units \| Vesting on February 1, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage				20.00%
Chief Executive Officer \| Restricted units \| Vesting on August 1, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage				40.00%
Chief Executive Officer \| Restricted units \| Vesting on February 1, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage				20.00%
Chief Executive Officer \| Restricted units \| Vesting on February 1, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage				20.00%
Executive Officer \| Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted			687,500
Fair value of units granted				$ 22.60
Chief Financial Officer \| Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period				4 years
Chief Financial Officer \| Restricted units \| Percentage Based Vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted			137,500
Chief Financial Officer \| Restricted units \| Equal Annual Based Vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted			25,000
Chief Financial Officer \| Restricted units \| Vesting on March 1, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage				45.46%
Chief Financial Officer \| Restricted units \| Vesting on March 1, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage				54.54%
Certain Partnership Employees \| Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted	304,901
Vesting period				4 years
Certain Partnership Employees \| Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted		100,000
Minimum [Member] \| Certain Partnership Employees \| Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of units granted				$ 23.56
Minimum [Member] \| Certain Partnership Employees \| Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of units granted				23.16
Maximum \| Certain Partnership Employees \| Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of units granted				25.50
Maximum \| Certain Partnership Employees \| Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of units granted				$ 23.70

Equity Based Compensation - Phantom Units (Details) - Phantom units - shares		12 Months Ended
	Apr. 21, 2014	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted	106,718	106,718
Certain Partnership Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted	100,000
Independent Directors Of Enable GP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted		6,718

Equity Based Compensation - Equity Units Activity (Details) - USD ($) $ in Millions			12 Months Ended
	Jun. 02, 2014	Apr. 21, 2014	Dec. 31, 2014
Performance units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Number of Units Outstanding at 12/31/2013			0
Units granted	563,963		563,963
Vested			(1,545)
Forfeited			(9,837)
Number of Units Outstanding at 12/31/2014			552,581
Aggregate Intrinsic Value, Units Outstanding at 12/31/2014			$ 11
Number of Units Fully Vested at 12/31/2014			1,545
Aggregate Intrinsic Value, Units Fully Vested at 12/31/2014			$ 0
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Number of Units Outstanding at 12/31/2013			0
Units granted			992,401
Vested			(150,515)
Forfeited			(3,818)
Number of Units Outstanding at 12/31/2014			838,068
Aggregate Intrinsic Value, Units Outstanding at 12/31/2014			$ 16
Number of Units Fully Vested at 12/31/2014			150,515
Aggregate Intrinsic Value, Units Fully Vested at 12/31/2014			$ 0
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Number of Units Outstanding at 12/31/2013			0
Units granted		106,718	106,718
Vested			(500)
Forfeited			(7,500)
Number of Units Outstanding at 12/31/2014			98,718
Aggregate Intrinsic Value, Units Outstanding at 12/31/2014			$ 2
Number of Units Fully Vested at 12/31/2014			500
Aggregate Intrinsic Value, Units Fully Vested at 12/31/2014			$ 0

Equity Based Compensation - Unrecognized Compensation Cost (Details) $ in Millions	12 Months Ended
	Dec. 31, 2014 USD ($) shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 25
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 11
Weighted Average to be Recognized (In years)	2 years 9 months 22 days
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 13
Weighted Average to be Recognized (In years)	1 year 10 months 21 days
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 1
Weighted Average to be Recognized (In years)	4 months 10 days
Long Term Incentive Plan \| Common Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for issuance \| shares	11,458,073

- Schedule of Financial Data for Business Segments and Services (Details) $ in Millions	3 Months Ended								12 Months Ended			13 Months Ended
	Dec. 31, 2014 USD ($)	Sep. 30, 2014 USD ($)	Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Sep. 30, 2013 USD ($)	Jun. 30, 2013 USD ($)	Mar. 31, 2013 USD ($)	Dec. 31, 2014 USD ($) segment	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	May 29, 2014	May 30, 2014	Apr. 30, 2013	Jun. 30, 2012
Segment Reporting Information [Line Items]
Number of reportable segments \| segment									2
Revenues	$ 735	$ 803	$ 827	$ 1,002	$ 824	$ 792	$ 612	$ 261	$ 3,367	$ 2,489	$ 952
Cost of goods sold, excluding depreciation and amortization	364	439	478	633	486	459	323	45	1,914	1,313	129
Operation and maintenance									527	429	267
Depreciation and amortization									276	212	106
Impairment									8	12	0
Taxes other than income tax									56	54	34
Operating Income	134	$ 152	$ 138	$ 162	130	$ 115	116	$ 108	586	469	416
Total assets	11,837				11,232				11,837	11,232	6,482
Capital expenditures									837	573	202
Equity in earnings of equity method affiliates									20	15	31
Investment in equity method affiliates	348				198				348	198
Waskom
Segment Reporting Information [Line Items]
Equity interest before remaining interest acquired, percentage															50.00%
SESH
Segment Reporting Information [Line Items]
Investment in equity method affiliates	$ 348				198				$ 348	198
Ownership percentage	49.90%								49.90%					50.00%
Limited partner ownership interest, exercisable as early as May 2014		24.95%										24.95%
Equity method investment, ownership interest, contributed by limited partner, percentage													24.95%
Gathering and Processing
Segment Reporting Information [Line Items]
Revenues									$ 2,424	1,740	502
Cost of goods sold, excluding depreciation and amortization									1,585	1,075	124
Operation and maintenance									297	222	114
Depreciation and amortization									160	117	50
Impairment									8	12
Taxes other than income tax									25	20	5
Operating Income									349	294	209
Total assets	$ 8,356				7,157				8,356	7,157	2,439
Capital expenditures									740	431	70
Transportation and Storage
Segment Reporting Information [Line Items]
Revenues									1,577	1,149	502
Cost of goods sold, excluding depreciation and amortization									961	636	55
Operation and maintenance									232	209	155
Depreciation and amortization									116	95	56
Impairment									0	0
Taxes other than income tax									31	34	29
Operating Income									237	175	207
Total assets	5,493				5,717				5,493	5,717	4,052
Capital expenditures									103	142	132
Eliminations
Segment Reporting Information [Line Items]
Revenues									(634)	(400)	(52)
Cost of goods sold, excluding depreciation and amortization									(632)	(398)	(50)
Operation and maintenance									(2)	(2)	(2)
Depreciation and amortization									0	0	0
Impairment									0	0
Taxes other than income tax									0	0	0
Operating Income									0	0	0
Total assets	(2,012)				(1,642)				(2,012)	(1,642)	(9)
Capital expenditures									(6)	0	0
CenterPoint \| SESH
Segment Reporting Information [Line Items]
Distributed ownership percentage												25.05%
Other Income (Expense) \| Waskom
Segment Reporting Information [Line Items]
Equity in earnings of equity method affiliates									0	0	5
Other Income (Expense) \| SESH
Segment Reporting Information [Line Items]
Equity in earnings of equity method affiliates							$ 4		20	15	26
Investments in Equity Method Affiliates \| SESH
Segment Reporting Information [Line Items]
Equity in earnings of equity method affiliates									20	15
Investment in equity method affiliates	$ 348				$ 198				$ 348	$ 198	$ 405

Quarterly Financial Data (Unaudited) - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Apr. 30, 2013	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues (including revenues from affiliates (Note 13))	$ 735	$ 803	$ 827	$ 1,002	$ 824	$ 792	$ 612	$ 261			$ 3,367	$ 2,489	$ 952
Cost of Goods Sold, excluding depreciation and amortization (including expenses from affiliates (Note 13))	364	439	478	633	486	459	323	45			1,914	1,313	129
Operating income	134	152	138	162	130	115	116	108			586	469	416
Net income	123	139	121	150	116	105	1,338	59	$ 1,326	$ 292	533	1,618	316
Net income attributable to Enable Midstream Partners, LP	$ 122	$ 139	$ 120	$ 149	$ 115	$ 104	$ 1,337	$ 59			530	289	0
Subordinated Units
Net income attributable to Enable Midstream Partners, LP											$ 191	$ 0	$ 0
Basic and diluted earnings per unit (Note 4) (in dollars per unit)	$ 0.29	$ 0.33	$ 0.29	$ 0.00	$ 0.00	$ 0.00	$ 0.00	$ 0.00			$ 1.28	$ 0.00	$ 0.00
Common Units
Net income attributable to Enable Midstream Partners, LP											$ 339	$ 289	$ 0
Basic and diluted earnings per unit (Note 4) (in dollars per unit)	$ 0.29	$ 0.33	$ 0.29	$ 0.38	$ 0.29	$ 0.27	$ 0.18	$ 0.00			$ 1.29	$ 0.74	$ 0.00