View Filing Data

Impairments (Note 8, Note 11)

318

276

212

1,134

Taxes other than income taxes

Total Cost and Expenses

3,130

2,781

2,020

Interest expense (including expenses from affiliates (Note 14))

(712)

586

469

Other Income (Expense):

(90)

(70)

(67)

Interest income—affiliated companies

Other, net

(1)

Total Other Income (Expense)

(59)

(51)

(43)

(Loss) Income Before Income Taxes

(771)

535

426

Income tax expense (benefit)

(1,192)

Net (Loss) Income

(771)

533

1,618

Less: Net (loss) income attributable to noncontrolling interest

(19)

Net (Loss) Income attributable to Enable Midstream Partners, LP

(752)

530

1,615

Limited partners' interest in net (loss) income attributable to Enable Midstream Partners, LP (Note 4)

$ (752)

$ 530

$ 289

Basic and diluted weighted average number of outstanding partner units (Note 4) (in units)

422

412

390

Common Units

Other Income (Expense):

Limited partners' interest in net (loss) income attributable to Enable Midstream Partners, LP (Note 4)

$ (381)

$ 339

$ 289

Basic and diluted earnings per unit (Note 4) (in dollars per unit)

$ (1.78)

$ 1.29

$ 0.74

Basic and diluted weighted average number of outstanding partner units (Note 4) (in units)

214

264

390

Subordinated Units

Other Income (Expense):

Limited partners' interest in net (loss) income attributable to Enable Midstream Partners, LP (Note 4)

$ (371)

$ 191

$ 0

Basic and diluted earnings per unit (Note 4) (in dollars per unit)

$ (1.78)

$ 1.28

$ 0.00

Basic and diluted weighted average number of outstanding partner units (Note 4) (in units)

208

148

[1]	The Partnership had no external customers accounting for 10% or more of revenues in periods shown. See Note 14 for revenues from affiliated companies.

Combined and Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net income	$ (771)	$ 533	$ 1,618
Comprehensive (loss) income	(771)	533	1,618
Less: Comprehensive (loss) income attributable to noncontrolling interest	(19)	3	3
Comprehensive (loss) income attributable to Enable Midstream Partners, LP	$ (752)	$ 530	$ 1,615

Consolidated Balance Sheets - USD ($)
$ in Millions

Dec. 31, 2015

Dec. 31, 2014

Current Assets:

Cash and cash equivalents

$ 4

$ 12

Accounts receivable

245

254

Accounts receivable—affiliated companies

381

438

Property, Plant and Equipment:

Property, plant and equipment

11,293

10,464

Less accumulated depreciation and amortization

1,162

882

Property, plant and equipment, net

10,131

9,582

Other Assets:

Intangible assets, net

333

357

Investment in equity method affiliates

1,068

344

348

Other

Total other assets

726

1,817

Total Assets

11,238

11,837

Current Liabilities:

Accounts payable

248

275

Accounts payable—affiliated companies

Short-term debt

^[1]

236

253

Taxes accrued

Gas imbalances

Other

Total current liabilities

615

671

Other Liabilities:

Accumulated deferred income taxes, net

Notes payable—affiliated companies

363

Regulatory liabilities

Other

Total other liabilities

409

415

Long-Term Debt

2,683

1,928

Commitments and Contingencies (Note 15)

214541422

3,714

4,353

207855430

3,805

4,439

Partners’ Capital:

Total partners' capital attributable to Enable Midstream Partners, LP Partners’ Capital

7,519

8,792

Noncontrolling interest

Total Partners’ Capital

7,531

8,823

Total Liabilities and Partners’ Capital

$ 11,238

$ 11,837

[1]	Short-term debt includes $236 million and $253 million of commercial paper as of December 31, 2015 and 2014, respectively.

Consolidated Balance Sheets - Parenthetical - shares	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Common units issued	214,541,422	214,417,908
Common units outstanding	214,541,422	214,417,908
Subordinated units issued	207,855,430	207,855,430
Subordinated units outstanding	207,855,430	207,855,430

Combined and Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Flows from Operating Activities:
Net income	$ (771)	$ 533	$ 1,618
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	318	276	212
Deferred income taxes	(1)	1	(1,194)
Impairments	1,134	8	12
Gain on sale/retirement of assets	5	0	2
Equity in earnings of equity method affiliates, net of distributions	5	3	9
Equity based compensation	9	13	0
Amortization of debt costs and discount (premium)	(2)	(1)	0
Changes in other assets and liabilities:
Accounts receivable, net	9	52	(81)
Accounts receivable—affiliated companies	6	1	(4)
Inventory	10	7	(6)
Gas imbalance assets	22	(35)	2
Income taxes receivable	0	0	19
Other current assets	2	17	15
Other assets	(4)	5	(1)
Accounts payable	0	(138)	62
Accounts payable—affiliated companies	(29)	(2)	3
Gas imbalance liabilities	12	0	0
Other current liabilities	6	29	(2)
Other liabilities	(5)	0	(18)
Net cash provided by operating activities	726	769	648
Cash Flows from Investing Activities:
Capital expenditures	(869)	(837)	(573)
Acquisitions, net of cash acquired	(80)	0	0
Proceeds from sale of assets	3	13	0
Decrease (increase) in notes receivable—affiliated companies	0	0	434
Return of investment in equity method affiliates	8	198	0
Investment in equity method affiliates	(8)	(189)	0
Other, net	0	0	(1)
Net cash provided by (used in) investing activities	(946)	(815)	(140)
Cash Flows from Financing Activities:
Repayment of long term debt	0	(1,500)	0
Proceeds from long term debt, net of issuance costs	450	1,635	1,046
Proceeds from revolving credit facility	585	122	1,126
Repayment of revolving credit facility	(275)	(495)	(754)
Increase in short-term debt	(17)	253	0
Decrease of notes payable—affiliated companies	0	0	(1,542)
Repayment of advance with affiliated companies	0	0	(136)
Capital contributions from partners	0	464	43
Distributions to partners	(531)	(529)	(183)
Net cash provided by (used in) financing activities	212	(50)	(400)
Net Increase in Cash and Cash Equivalents	(8)	(96)	108
Cash and Cash Equivalents at Beginning of Period	12	108	0
Cash and Cash Equivalents at End of Period	$ 4	$ 12	$ 108

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, 2012	$ 3,221		$ 3,221	$ (6)	$ 3,215	$ 6		$ 0
Balance, beginning of period, units at Dec. 31, 2012								0
Changes in Partners' Capital
Net income	1,326		1,326	0	1,326	0		$ 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		4,252	0	4,252	6		$ 0
Balance, beginning of period at Dec. 31, 2012	3,221		3,221	(6)	3,215	6		$ 0
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		4,252	0	4,252	6		$ 0
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 Offering common units, units							25
Issuance of Offering 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
Changes in Partners' Capital
Net income	(771)				(752)	(19)	(379)	(373)
Issuance of units upon acquisition	1	$ 1			1
Distributions to partners	(531)				(531)		(270)	$ (261)
Equity based compensation	9				9		$ 9
Balance, end of period, units at Dec. 31, 2015							214	208
Balance, end of period at Dec. 31, 2015	$ 7,531				$ 7,519	$ 12	$ 3,714	$ 3,805

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

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 services primarily to natural gas producers, utilities and industrial customers. The natural gas gathering and processing assets are located in five 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, 2015, CenterPoint Energy held approximately 55.4% of the limited partner interests in the Partnership, or 94,151,707 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, Enable Midstream Services) 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, Enable Midstream Services). See Note 16 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 June 29, 2015, the financial statements reflect a 49.90% interest in SESH. On June 12, 2015, CenterPoint Energy exercised its put right with respect to a 0.1% interest in SESH. Pursuant to the put right, on June 30, 2015, CenterPoint Energy contributed its remaining 0.1% interest in SESH to the Partnership in exchange for 25,341 common units representing limited partner interests in the Partnership. As of December 31, 2015, the Partnership owned a 50% interest in SESH. See Note 9 for further discussion of SESH.

In addition, as of December 31, 2015 and 2014, as a result of the acquisition of Enogex on May 1, 2013, the Partnership held a 50% ownership interest in Atoka. At December 31, 2015 and 2014, the Partnership consolidated Atoka in its Combined and Consolidated Financial Statements as EOIT 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 18.

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.

Revenue Recognition

The Partnership generates the majority of its revenues from midstream energy services, including natural gas gathering, processing, transportation and storage and crude oil gathering. The Partnership performs these services under various contractual arrangements, which include fee-based contract arrangements and arrangements pursuant to which it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. While the Partnership's transactions vary in form, the essential element of each transaction is the use of its assets to transport a product or provide a processed product to a customer. The Partnership reflects revenue as Product sales and Service revenue on the Combined and Consolidated Statements of Income as follows:

Product sales: Product sales represent the sale of natural gas, NGLs, crude oil and condensate where the product is purchased and used in connection with providing the Partnership's midstream services.

Service revenue: Service revenue represents all other revenue generated as a result of performing the Partnership's midstream services.

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 $17 million and $18 million of deferred revenues on the Consolidated Balance Sheets at December 31, 2015 and 2014, 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, 2015, 2014 and 2013, one third party purchased approximately 18%, 21% and 30%, respectively, of the NGLs delivered off our system, which accounted for approximately $108 million, $235 million and $232 million, or 4%, 7% and 9%, respectively, of total revenue. Other than revenues from affiliates discussed in Note 14, there are no other revenue concentrations with individual customers in the years ended December 31, 2015, 2014, and 2013.

Natural Gas and Natural Gas Liquids Purchases

Cost of natural gas and natural gas liquids represents cost of our natural gas and natural gas liquids purchased exclusive of depreciation, Operation and maintenance and General and administrative expenses and consists primarily of product and fuel costs. 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 natural gas and natural gas liquids, excluding Depreciation and amortization on the Combined and Consolidated Statements of Income.

Operation and Maintenance and General and Administrative Expense

Operation and maintenance expense represents the cost of our service related revenues and consists primarily of labor expenses, lease costs, utility costs, insurance premiums and repairs and maintenance expenses directly related with the operations of assets. General and administrative expense represents cost incurred to manage the business. This expense includes cost of general corporate services, such as treasury, accounting, legal, information technology and human resources and all other expenses necessary or appropriate to the conduct of business. Any Operation and maintenance expense and General and administrative expense associated with product sales is immaterial.

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, 2015 or 2014.

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, Enable Midstream Services) and are taxable at the individual partner level. For more information, see Note 16.

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 $4 million and $12 million of cash and cash equivalents as of December 31, 2015 and 2014, 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 at least quarterly, 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, 2015 and 2014.

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. There were no material write-downs related to materials and supplies inventory for the year ended December 31, 2015. 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, 2015, 2014 and 2013, the Partnership recorded write-downs to market value related to natural gas and natural gas liquids inventory of $13 million, $4 million and $4 million, respectively. The cost of gas associated with sales of natural gas and natural gas liquids inventory is presented in Cost of natural gas and natural gas liquids, excluding depreciation and amortization on the Combined and Consolidated Statements of Income.



	December 31,
	2015		2014
	(In millions)
Materials and supplies	$	34	$	39
Natural gas and natural gas liquids inventories	19		24
Total	$	53	$	63

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 natural gas 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. For more information, see Note 11.

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. For more information, see Note 8.

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, 2015 and 2014, these removal costs of $18 million and $16 million, respectively, 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, 2015, 2014 and 2013, the Partnership capitalized interest and AFUDC of $10 million, $8 million and $7 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 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, 2015
Accounting Changes and Error Corrections [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements Revenue from Contracts with Customers 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. In August 2015, FASB issued ASU No. 2015-14, "Revenue from Contracts with Customers (Topic 606)—Deferral of the Effective Date," which deferred the effective date of ASU 2014-09 by one year to December 15, 2017 for annual reporting periods beginning after that date. The FASB also proposed permitting early adoption of the standard, but not before the original effective date of December 15, 2016. The Partnership is currently evaluating the impact, if any, the adoption of this standard will have on our Combined and Consolidated Financial Statements and related disclosures. Consolidation In February 2015, FASB issued ASU No. 2015-02, “Consolidation,” to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted retrospectively in previously issued financial statements for one or more years with a cumulative-effect adjustment to partners’ capital as of the beginning of the first year restated. The Partnership does not expect the adoption of this standard will have a material impact on our Combined and Consolidated Financial Statements and related disclosures. Presentation of Debt Issuance Costs In April 2015, FASB issued ASU No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs." This standard amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a deduction from the carrying amount of the related debt liability instead of a deferred charge. It is effective for annual reporting periods beginning after December 15, 2015, but early adoption is permitted. As of December 31, 2015 and 2014, the Partnership had unamortized debt expense of $12 million and $13 million, respectively, which would have been classified as a reduction of long-term debt in our Consolidated Balance Sheets had we adopted this standard in the fourth quarter of 2015. The Partnership will adopt ASU No. 2015-03 in the first quarter of 2016 and it will be applied retrospectively to each period presented in the Combined and Consolidated Financial Statements. In August 2015, the FASB issued ASU No. 2015-15, "Interest—Imputation of Interest: Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements—Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting." This ASU adds SEC paragraphs pursuant to the SEC Staff Announcement at the June 18, 2015, Emerging Issues Task Force meeting about the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements to this topic. Given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to line-of-credit arrangements, the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Partnership has elected to continue to carry debt issuance costs related to line-of-credit arrangements as an asset and amortize the deferred debt issuance costs over the term of the related line-of-credit arrangement. The Partnership will adopt the amendment in the first quarter of 2016 and has determined the adoption of ASU No. 2015-15 will have no impact on our Combined and Consolidated Financial Statements and related disclosures. Customer's Accounting for Fees Paid in a Cloud Computing Arrangement In April 2015, the FASB issued ASU No. 2015-05, "Customer's Accounting for Fees Paid in a Cloud Computing Arrangement." This standard provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. The new guidance does not change the accounting for a customer's accounting for service contracts. ASU No. 2015-05 is effective for interim and annual reporting periods beginning after December 15, 2015. The Partnership will adopt the amendment in the first quarter of 2016 and has determined the adoption of ASU No. 2015-05 will have no impact on our Combined and Consolidated Financial Statements and related disclosures. Simplifying the Measurement of Inventory In July 2015, the FASB issued ASU No. 2015-11, "Simplifying the Measurement of Inventory." Under this ASU, inventory will be measured at the “lower of cost and net realizable value,” and options that currently exist for “market value” will be eliminated. The ASU defines net realizable value as the “estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation.” No other changes were made to the current guidance on inventory measurement. ASU 2015-11 is effective for interim and annual periods beginning after December 15, 2016. Early application is permitted and should be applied prospectively. The Partnership will adopt ASU No. 2015-11 in the first quarter of 2016 and has determined the amendment will have no impact to our Combined and Consolidated Financial Statements and related disclosures. Simplifying the Accounting for Measurement-Period Adjustments In September 2015, the FASB issued ASU No. 2015-16, "Business Combinations—Simplifying the Accounting for Measurement-Period Adjustments." Under this ASU, acquirers are required to record, in the same period's financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. Acquirers are required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. ASU 2015-16 is effective for interim and annual periods beginning after December 15, 2016. The amendments in this update should be applied prospectively to adjustments to provisional amounts that occur after the effective date with earlier application permitted for financial statements that have not been issued. This amendment has no impact to our current Combined and Consolidated Financial Statements, but could affect future disclosures. Balance Sheet Classification of Deferred Taxes In November 2015, the FASB issued ASU No. 2016-17, "Income Taxes—Balance Sheet Classification of Deferred Taxes." This ASU eliminates the requirement to present deferred tax liabilities and assets as current and non-current in a classified balance sheet. Instead, all deferred tax assets and liabilities will be classified as non-current. ASU 2015-17 is effective for all interim and annual periods beginning after December 16, 2015 and early application is permitted. The amendments in this update may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. The Partnership does not expect the adoption of this standard will have a material impact on our Combined and Consolidated Financial Statements and related disclosures.

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.

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
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=56949863&loc=d3e22583-107794

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Indirect Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6515603

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=56949863&loc=d3e22580-107794

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.10-01.(b)(6))
-URI http://asc.fasb.org/extlink&oid=27015980&loc=d3e46468-122699

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Accounting Change
-URI http://asc.fasb.org/extlink&oid=6503790

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=56949863&loc=d3e22499-107794

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Retrospective Application
-URI http://asc.fasb.org/extlink&oid=6523989

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section 45
-Paragraph 13
-URI http://asc.fasb.org/extlink&oid=51655806&loc=d3e765-108305

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section 45
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=51655806&loc=d3e725-108305

Acquisitions

12 Months Ended

Dec. 31, 2015

Business Combinations [Abstract]

Acquisitions

Monarch

On April 22, 2015, Enable entered into an agreement with Monarch Natural Gas, LLC, pursuant to which the Partnership agreed to acquire approximately 106 miles of gathering pipeline, approximately 5,000 horsepower of associated compression, right-of-ways and certain other midstream assets that provide natural gas gathering services in the Greater Granite Wash area of Texas. The transaction closed on May 1, 2015. The aggregate purchase price for this transaction was approximately $80 million, which was funded from cash generated from operations and borrowings under our Revolving Credit Facility.

The acquisition was accounted for as a business combination. During the third quarter of 2015, the Partnership, with the assistance of a third-party valuation expert, finalized the purchase price allocation as of May 1, 2015.



Purchase price allocation (in millions):
Property, plant and equipment	$	51
Intangibles	10
Goodwill	19
Total	$	80

The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 15 years. Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Anadarko Basin. See Note 8 for further information related to the Partnership's goodwill impairment. The Partnership incurred less than $1 million of acquisition costs associated with this transaction, which are included in General and administrative expense in the Combined and Consolidated Statements of Income.

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.

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).

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1497-128463

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1490-128463

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1392-128463

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e7008-128479

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1486-128463

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6927-128479

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=56956791&loc=d3e4845-128472

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1500-128463

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1524-128463

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e7000-128479

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=56956791&loc=d3e4922-128472

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=56956791&loc=d3e4934-128472

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=56956791&loc=d3e4926-128472

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1383-128463

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6996-128479

Earnings Per Limited Partner Unit

Earnings Per Limited Partner Unit

12 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

Limited partners’ interest in net (loss) income attributable to the Partnership and basic and diluted earnings per unit reflect net (loss) 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 (loss) 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 the unit-based awards discussed in Note 17 was less than $0.01 per unit during the years ended December 31, 2015 and 2014.

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



	Year Ended December 31,
	2015			2014		2013
	(In millions, except per unit data)
Net (loss) income attributable to Enable Midstream Partners, LP	$	(752	)	$	530	$	1,615
Less general partner interest in net (loss) income	—			—		—
Limited partner interest in net (loss) income attributable to Enable Midstream Partners, LP	$	(752	)	$	530	$	1,615
Net (loss) income allocable to common units	$	(381	)	$	339	$	289
Net (loss) income allocable to subordinated units	(371		)	191		—
Limited partner interest in net (loss) income attributable to Enable Midstream Partners, LP	$	(752	)	$	530	$	289
Basic and diluted weighted average number of outstanding limited partner units
Common units	214			264		390
Subordinated units	208			148		—
Total	422			412		390
Basic and diluted (loss) earnings per limited partner unit
Common units	$	(1.78	)	$	1.29	$	0.74
Subordinated units	$	(1.78	)	$	1.28	$	—

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

12 Months Ended

Dec. 31, 2015

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 2015 and 2014 (in millions, except for per unit amounts):

Quarter Ended

Record Date

Payment Date

Per Unit Distribution

Total Cash Distribution

December 31, 2015 ⁽¹⁾

February 2, 2016

February 12, 2016

0.318

134

September 30, 2015

November 3, 2015

November 13, 2015

0.318

134

June 30, 2015

August 3, 2015

August 13, 2015

0.316

134

March 31, 2015

May 5, 2015

May 15, 2015

0.3125

132

December 31, 2014

February 4, 2015

February 13, 2015

0.30875

130

September 30, 2014

November 4, 2014

November 14, 2014

0.3025

128

June 30, 2014 ⁽²⁾

August 4, 2014

August 14, 2014

0.2464

104

_____________________


(1)	The board of directors of Enable GP declared this $0.318 per common unit cash distribution on January 22, 2016, to be paid on February 12, 2016, to unitholders of record at the close of business on February 2, 2016.


(2)	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, 2015

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)	2015		2014
		(In millions)
Property, plant and equipment, gross:
Gathering and Processing	33	$	6,478	$	5,560
Transportation and Storage	36	4,444		4,300
Construction work-in-progress		371		604
Total		$	11,293	$	10,464
Accumulated depreciation:
Gathering and Processing		510		343
Transportation and Storage		652		539
Total accumulated depreciation		1,162		882
Property, plant and equipment, net		$	10,131	$	9,582

The Partnership recorded depreciation expense of $291 million, $249 million and $194 million during the years ended December 31, 2015, 2014 and 2013, respectively.

Intangible Assets, Net

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets, Net

Prior to May 1, 2013, the Partnership did not have any intangible assets. The Partnership has $405 million as of December 31, 2015, in intangible assets associated with customer relationships due to the acquisition of Enogex and Monarch Natural Gas, LLC.

Intangible assets consist of the following:



	December 31,
	2015		2014
	(In millions)
Customer relationships:
Total intangible assets	$	405	$	401
Accumulated amortization	72		45
Net intangible assets	$	333	$	356

The Partnership determined that intangible assets related to customer relationships have a weighted average useful life of 15 years. 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, $27 million and $18 million during the years ended December 31, 2015, 2014 and 2013, respectively. The following table summarizes the Partnership's expected amortization of intangible assets for each of the next five years:



	2016		2017		2018		2019		2020
	(In millions)
Expected amortization of intangible assets	$	27	$	27	$	27	$	27	$	27

Goodwill

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

Equity Method Investments and Joint Ventures [Abstract]

For the periods ended prior to September 30, 2015, the goodwill associated with the gathering and processing reportable segment is primarily related to the acquisitions of Enogex, Waskom and Monarch. The Partnership recognized $438 million of goodwill as a result of the acquisition of Enogex, which occurred at the time of the formation of the Partnership in 2013. The $579 million of goodwill associated with the transportation and storage reportable segment is related to the original acquisitions of EGT and MRT in 1997 by predecessors of the Partnership. The Partnership tests 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. Subsequent to the completion of the October 1, 2014 annual test and previous interim assessment as of December 31, 2014, the crude oil and natural gas industry was impacted by further commodity price declines, which consequently resulted in decreased producer activity in certain regions in which the Partnership operates. Due to the continuing commodity price declines, the resulting decreases in forward commodity prices and forecasted producer activities, and an increase in the weighted average cost of capital, the Partnership determined that the impact on our forecasted discounted cash flows for our gathering and processing and transportation and storage reportable segments would be significantly reduced. As a result, when the Partnership performed the first step of our annual goodwill impairment analysis as of October 1, 2015, we determined that the carrying value of the gathering and processing and transportation and storage reportable segments exceeded fair value. The Partnership completed the second step of the goodwill impairment analysis by comparing the implied fair value of the reporting unit to the carrying amount of that goodwill and determined that goodwill was completely impaired in the amount of $1,087 million, which is included in Impairments on the Combined and Consolidated Statements of Income for the year ended December 31, 2015.

The change in carrying amount of goodwill in each of our reportable segments is as follows:



	Gathering and Processing			Transportation and Storage			Total
	(in millions)
Balance as of December 13, 2013	$	489		$	579		$	1,068

Balance as of December 31, 2014	489			579			1,068
Acquisition of Monarch	19			—			19
Goodwill impairment	(508		)	(579		)	(1,087		)
Balance as of December 31, 2015	$	—		$	—		$	—

Investment in Equity Method Affiliates

12 Months Ended

Dec. 31, 2015

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, the Partnership held a 24.95% interest in SESH, which is accounted for as an investment in equity method affiliates, and 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. For the period from May 30, 2014 through June 29, 2015, the Partnership held a 49.90% interest in SESH. On June 12, 2015, CenterPoint Energy exercised its put right with respect to its remaining 0.1% interest in SESH. Pursuant to the put right, on June 30, 2015, CenterPoint Energy contributed a 0.1% interest in SESH to the Partnership in exchange for 25,341 common units representing limited partner interests in the Partnership, which had a fair value of $1 million based upon the closing market price of the Partnership's common units. Spectra Energy Partners, LP owns 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, or does not have the ability to exercise certain control rights, Spectra Energy Partners, LP could have the right to purchase our interest in SESH at fair market value. As of December 31, 2015, the Partnership owned a 50% 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 quarter ended June 30, 2014 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 50% 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.

The Partnership shares operations of SESH with Spectra Energy Partners, LP under service agreements. The Partnership is responsible for the field operations of SESH. SESH reimburses each party for actual costs incurred, which are billed based upon a combination of direct charges and allocations. During the years ended December 31, 2015, 2014 and 2013, the Partnership billed SESH $12 million, $13 million and $15 million, respectively, associated with these service agreements.

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, 2015, 2014 and 2013.

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
Interest acquisition of SESH	1
Equity in earnings of equity method affiliate	29
Contributions to equity method affiliate	8
Distributions from equity method affiliate	(42		)
Balance as of December 31, 2015	$	344

Equity in Earnings of Equity Method Affiliates:



	Year Ended December 31,
	2015		2014		2013
	(In millions)
SESH	$	29	$	20	$	15

Distributions from Equity Method Affiliates:



	Year Ended December 31,
	2015		2014		2013
	(In millions)
SESH ⁽¹⁾	$	42	$	23	$	24

_____________________


(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,
	2015			2014
	(In millions)
Balance Sheets:
Current assets	$	45		$	57
Property, plant and equipment, net	1,127			1,127
Total assets	$	1,172		$	1,184
Current liabilities	$	18		$	19
Long-term debt	397			397
Members’ equity	757			768
Total liabilities and members’ equity	$	1,172		$	1,184
Reconciliation:
Investment in SESH	$	344		$	348
Less: Capitalized interest on investment in SESH	(1		)	(2		)
The Partnership’s share of members' equity	$	343		$	346



	Year Ended December 31,
	2015		2014		2013
	(In millions)
Income Statements:
Revenues	$	115	$	108	$	107
Operating income	71		69		66
Net income	57		48		47

Debt

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Debt

The following table presents the Partnership's outstanding debt as of December 31, 2015 and 2014.



	December 31,
	2015		2014
	(In millions)
Commercial Paper	$	236	$	253
Revolving Credit Facility	310		—
2015 Term Loan Facility	450		—
Notes payable—affiliated companies	363		363
2019 Notes	500		500
2024 Notes	600		600
2044 Notes	550		550
EOIT Senior Notes	250		250
Premium on long-term debt	23		28
Total debt	3,282		2,544
Less amount classified as short-term debt⁽¹⁾	236		253
Less Notes payable—affiliated companies (Note 14)	363		363
Total long-term debt	$	2,683	$	1,928

___________________


(1)	Short-term debt includes $236 million and $253 million of commercial paper as of December 31, 2015 and 2014, respectively.

Maturities of outstanding debt, excluding unamortized premiums, are as follows (in millions):



2016	$	236
2017	363
2018	450
2019	500
2020	560
Thereafter	1,150

Revolving Credit Facility

On June 18, 2015, the Partnership amended and restated its Revolving Credit Facility to, among other things, increase the borrowing capacity thereunder to $1.75 billion and extend its maturity date to June 18, 2020. As of December 31, 2015, there were $310 million of principal advances and $3 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 weighted average interest rate of the Revolving Credit Facility was 1.85% as of December 31, 2015.

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, 2015, the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was 1.50% 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, 2015, the commitment fee under the Revolving Credit Facility was 0.20% 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 any three fiscal quarters including and following any fiscal quarter in which the aggregate value of one or more acquisitions by us or certain of our subsidiaries with a purchase price of at least $25 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 and non-recourse indebtedness) 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

The Partnership has 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. There was $236 million and $253 million outstanding under our commercial paper program as of December 31, 2015 and 2014, respectively. Any reduction in our credit ratings could prevent us from accessing the commercial paper markets. The weighted average interest rate for the outstanding commercial paper was 1.63% as of December 31, 2015.

Term Loan Facilities

On July 31, 2015, the Partnership entered into a Term Loan Agreement dated as of July 31, 2015, providing for an unsecured three-year $450 million term loan facility (2015 Term Loan Facility). The entire $450 million principal amount of the 2015 Term Loan Facility was borrowed by Enable on July 31, 2015. The 2015 Term Loan Facility contains an option, which may be exercised up to two times, to extend the term of the 2015 Term Loan Facility, in each case, for an additional one-year term. The 2015 Term Loan Facility provides an option to prepay, without penalty or premium, the amount outstanding, or any portion thereof, in a minimum amount of $1 million, or any multiple of $0.5 million in excess thereof. As of December 31, 2015, there was $450 million outstanding under the 2015 Term Loan Facility.

The 2015 Term Loan Facility provides that outstanding borrowings 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 our applicable credit ratings. As of December 31, 2015, the applicable margin for LIBOR-based borrowings under the 2015 Term Loan Facility was 1.375% based on our credit ratings. As of December 31, 2015, the weighted average interest rate of the 2015 Term Loan Facility was 1.80%.

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 2013 Term Loan Facility, and certain of the proceeds were used to repay the EOIT $250 million variable rate term loan and the EOIT $200 million 6.875% senior notes due July 15, 2014, and for general corporate purposes. On July 15, 2014, the Partnership repaid the EOIT $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.

In connection with the issuance of the 2019 Notes, 2024 Notes and 2044 Notes, the Partnership, CenterPoint Energy Resources Corp., as guarantor, and RBS Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA) LLC, and RBC Capital Markets, LLC, as representatives of the initial purchasers, entered into a registration rights agreement whereby the Partnership and the guarantor agreed to file with the SEC a registration statement relating to a registered offer to exchange the 2019 Notes, 2024 Notes and 2044 Notes for new series of the Partnership's notes in the same aggregate principal amount as, and with terms substantially identical in all respects to, the 2019 Notes, 2024 Notes and 2044 Notes. The agreement provided for the accrual of additional interest if the Partnership did not complete an exchange offer by October 9, 2015. Because an exchange offer was not consummated by October 9, 2015, additional interest began accruing on the 2019 Notes, 2024 Notes and 2044 Notes on October 10, 2015, at a rate of 0.25% per year until the first 90-day period after such date. On December 29, 2015, the Partnership completed the exchange offer. As a result, the Partnership recognized approximately $1 million of additional interest expense during 2015.

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, 2015, the Partnership’s debt included EOIT’s $250 million 6.25% senior notes due March 2020 (the EOIT Senior Notes). The EOIT Senior Notes have $23 million unamortized premium at December 31, 2015, resulting in an effective interest rate of 5.6%, during the year ended December 31, 2015. 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.

Financing Costs

Unamortized debt expense of $18 million and $17 million at December 31, 2015 and 2014, 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 $23 million and $28 million at December 31, 2015 and 2014, respectively, is classified as either Long-Term Debt or Short-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 in the year ended December 31, 2014 associated with the retirement of the $1.05 billion 2013 Term Loan Facility and the EOIT $250 million variable rate term loan, which is included in Other, net on the Combined and Consolidated Statements of Income.

As of December 31, 2015, the Partnership and EOIT were in compliance with all of their debt agreements, including financial covenants.

Fair Value Measurements

12 Months Ended

Dec. 31, 2015

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, 2015, there were transfers between 2 and Level 3 investments, as shown in the reconciliation below.

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, commercial paper 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, 2015 and 2014:



	December 31, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-Term Debt
Long-term notes payable—affiliated companies (Level 2)	$	363	$	350	$	363	$	362
Revolving Credit Facility (Level 2)⁽¹⁾	310		310		—		—
2015 Term Loan Facility (Level 2)	450		450		—		—
EOIT Senior Notes (Level 2)	273		280		279		282
Enable Midstream Partners, LP, 2019, 2024 and 2044 Notes (Level 2)	1,650		1,255		1,649		1,592

___________________


(1)	Borrowing capacity is reduced by our borrowings outstanding under the commercial paper program. $236 million and $253 million of commercial paper was outstanding as of December 31, 2015 and 2014, respectively.

The fair value of the Partnership’s Long-term notes payable—affiliated companies, Revolving Credit Facility, and 2015 Term Loan Facility, along with the EOIT 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, 2015, 2014 and 2013, the Partnership remeasured the Service Star assets at fair value. At December 31, 2015 and 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 higher than expected losses of customers during 2015 and 2014 due to decreases of crude oil and natural gas prices. 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, 2015, 2014 and 2013, the Partnership recognized a $10 million, $7 million and $12 million impairment, respectively. The $10 million consisted of a $9 million write-down of property, plan and equipment and a $1 million write-down of materials and supplies inventory considered either excess or obsolete. The $7 million impairment consisted of write-downs 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.

At December 31, 2015, due to decreases of crude oil and natural gas prices during 2015, management reassessed the carrying value of the Partnership's investment in the Atoka assets, a component of the Gathering and Processing segment. Based on forecasted future undiscounted cash flows, management determined that the carrying value of the Atoka 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 intangible assets, the Partnership recognized a $25 million impairment during the year ended December 31, 2015. The $25 million impairment consisted of a $19 million write-down of property plant, and equipment and a $6 million write-down of intangible assets.

Additionally, during the year ended December 31, 2015, the Partnership recorded a $12 million impairment on jurisdictional pipelines in our transportation and storage segment.

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 as of December 31, 2015 and 2014:



December 31, 2015	Commodity Contracts						Gas Imbalances ⁽¹⁾
	Assets			Liabilities			Assets ⁽²⁾		Liabilities ⁽³⁾
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	17		$	3		$	—	$	—
Significant other observable inputs (Level 2)	10			—			17		$	20
Unobservable inputs (Level 3)	4			—			—		$	—
Total fair value	31			3			17		$	20
Netting adjustments	(3		)	(3		)	—		$	—
Total	$	28		$	—		$	17	$	20



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

______________________

(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 EOIT 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, 2015 and 2014.


(2)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $6 million and $4 million at December 31, 2015 and 2014, 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 $5 million and $1 million at December 31, 2015 and 2014, 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.

Changes in Level 3 Fair Value Measurements

The following tables provides a reconciliation of changes in the fair value of our Level 3 financial assets between the periods presented.



	Commodity Contracts
	Crude oil (for condensate) financial futures/swaps			Natural gas liquids financial futures/swaps
	(In millions)
Balance as of December 31, 2014	$	5		$	—
Gains included in earnings	12			10
Settlements	(8		)	(6		)
Transfers out of Level 3⁽¹⁾	(9		)	—
Balance as of December 31, 2015	$	—		$	4

______________________


(1)	The Partnership utilizes WTI crude swaps to manage exposure to condensate price risk. As the over-the-counter WTI crude swap is an active market, these derivative instruments will be classified as Level 2 as of December 31, 2015.

Quantitative Information on Level 3 Fair Value Measurements

The Partnership utilizes the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach to fair value are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in contracts.



	December 31, 2015
Product Group	Fair Value		Forward Curve Range
	(In millions)		(Per gallon)
Natural gas liquids	$	4	$0.339 - $0.436

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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, 2015

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, 2015 and 2014, 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 seek or 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, 2015 and 2014, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:



	December 31, 2015		December 31, 2014
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas—TBtu⁽¹⁾
Physical purchases/sales	2	51	4	32
Financial fixed futures/swaps	1	37	5	35
Financial basis futures/swaps	4	38	7	54
Crude oil (for condensate)—MBbl⁽²⁾
Financial futures/swaps	—	506	—	274
Natural gas liquids—MBbl⁽³⁾
Financial futures/swaps	75	1,011	—	—

____________________


(1)	As of December 31, 2015, 97.7% of the natural gas contracts have durations of one year or less and 2.3% have durations of more than one year and less than two years. As of December 31, 2014, 91.2% of the natural gas contracts had durations of one year or less, 6.5% had durations of more than one year and less than two years and 2.2% have durations of more than two years.


(2)	As each of December 31, 2015 and 2014, 100% of the crude oil (for condensate) contracts have durations of one year or less.


(3)	As of December 31, 2015, 100% of the natural gas liquid contracts have durations of one year or less.

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, 2015 and 2014 that were not designated as hedging instruments for accounting purposes are as follows:



		December 31, 2015				December 31, 2014
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	17	$	3	$	34	$	4
Physical purchases/sales	Other Current	1		—		1		—
Crude oil (for condensate)
Financial futures/swaps	Other Current	9		—		5		—
Natural gas liquids
Financial futures/swaps	Other Current	4		—		—		—
Total gross derivatives ⁽¹⁾		$	31	$	3	$	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, 2015 and 2014.

Income Statement Presentation Related to Derivative Instruments

The following table presents the effect of derivative instruments on the Partnership’s Consolidated Statements of Income for the years ended December 31, 2015, 2014 and 2013:



	Amounts Recognized in Income
	Year Ended December 31,
	2015			2014		2013
	(In millions)
Natural gas financial futures/swaps gains (losses)	$	26		$	37	$	(1	)
Natural gas physical purchases/sales gains (losses)	(9		)	1		—
Crude oil (for condensate) financial futures/swaps gains (losses)	12			9		—
Natural gas liquids financial futures/swaps gains (losses)	10			2		—
Total	$	39		$	49	$	(1	)

For derivatives not designated as hedges in the tables above, amounts recognized in income for the years ended December 31, 2015, 2014 and 2013, if any, are reported in Product Sales.

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, 2015, 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, 2015. 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.

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.

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

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624171-113959

Reference 3: 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=56946850&loc=d3e41620-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624163-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5579240-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4D
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624177-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=35736893&loc=d3e80784-113994

Reference 8: 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=56946850&loc=d3e41641-113959

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=56946850&loc=SL5579245-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4H
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624258-113959

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=35736893&loc=d3e80748-113994

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4K
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5708775-113959

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4J
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5708773-113959

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4A
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5618551-113959

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5580258-113959

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4E
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624181-113959

Reference 17: 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 18: 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=56946850&loc=d3e41638-113959

Reference 19: 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))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information

12 Months Ended

Dec. 31, 2015

Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:



	Year Ended December 31,
	2015		2014		2013
	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	85	$	77	$	65
Income taxes (refunds), net	1		1		(9		)
Non-cash transactions:
Accounts payable related to capital expenditures	52		93		43
Issuance of common units upon interest acquisition of SESH (Note 9)	1		161		—
Acquisition of Enogex	—		—		3,788

Related Party Transactions

12 Months Ended

Dec. 31, 2015

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.

Revenues

The Partnership’s revenues from affiliated companies accounted for 7%, 6%, and 9% of revenues during the years ended December 31, 2015, 2014 and 2013, 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,
	2015		2014		2013
	(In millions)
Gas transportation and storage service revenue — CenterPoint Energy	$	110	$	112	$	108
Natural gas product sales — CenterPoint Energy	7		22		70
Gas transportation and storage service revenue — OGE Energy ⁽¹⁾	37		39		32
Natural gas product sales — OGE Energy⁽¹⁾	8		13		14
Total revenues — affiliated companies	$	162	$	186	$	224

____________________

(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 Statements 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.

Cost of natural gas purchases

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,
	2015		2014		2013
	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	2	$	2	$	4
Cost of natural gas purchases — OGE Energy	15		19		8
Total cost of natural gas purchases — affiliated companies	$	17	$	21	$	12

Corporate services and seconded employee expense

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 seconded 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 2015 are $15 million and $11 million, respectively.

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



	Year Ended December 31,
	2015		2014		2013
	(In millions)
Seconded Employee Costs - CenterPoint Energy ⁽¹⁾	$	—	$	138	$	92
Corporate Services - CenterPoint Energy	15		29		38
Seconded Employee Costs - OGE Energy ⁽²⁾	35		105		78
Corporate Services - OGE Energy ⁽²⁾	11		17		18
Total corporate services and seconded employees expense	$	61	$	289	$	226

_________________________


(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 Statements of Income beginning on May 1, 2013.

Notes payable

The Partnership has outstanding long-term notes payable—affiliated companies to CenterPoint Energy at both December 31, 2015 and 2014 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, $8 million and $34 million, respectively during the years ended December 31, 2015, 2014 and 2013, respectively.

Notes receivable

The Partnership recorded no interest income—affiliated companies from CenterPoint Energy on notes receivable—affiliated companies during the years ended December 31, 2015 and 2014 and $9 million, during the year ended December 31, 2013.

Other

In 2015, EGT relocated a portion of its pipeline in Arkansas to improve reliability and increase capacity by constructing an approximately 28.5 mile new pipeline segment and abandoning approximately 34.2 miles of existing pipelines segments. In connection with the project, EGT sold an approximately 12.4 mile pipeline segment to CenterPoint Energy’s Arkansas LDC for its remaining book value of $1 million, and EGT will reimburse CenterPoint Energy’s Arkansas LDC approximately $7 million dollars for cost incurred in connecting the LDC to EGT’s new pipeline segment.

Commitments and Contingencies Disclosure [Abstract]

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, 2015

Commitments and Contingencies

Long-Term Agreements

Long-term Agreement with XTO. In March 2013 and February 2014, Enable Bakken entered into long-term agreements 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. Under the terms of the agreement, which includes volume commitments features or gross acreage dedication, Enable Bakken provides services to XTO over a gathering system constructed by Enable Bakken in Dunn and McKenzie Counties in North Dakota, which commenced operations in the fourth quarter of 2013, and a second gathering system constructed in Williams and Mountrail Counties in North Dakota, which commenced operations in the second quarter of 2015, with a combined capacity of up to 49,500 barrels per day. The remaining portion of the pipeline is expected to be placed in service during 2016 and 2017. As of December 31, 2015, the Partnership estimates the remaining construction costs to be $37 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,
	2016		2017		2018		2019		2020		After 2020		Total
	(In millions)
Noncancellable operating leases	$	14	$	5	$	3	$	1	$	—	$	—	$	23

Total rental expense for all operating leases was $32 million, $23 million and $12 million during the years ended December 31, 2015, 2014 and 2013, 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 included in General and administrative expense in the Statements of Combined and Consolidated Income.

The Partnership currently has 94 compression service agreements, of which 49 agreements are on a month-to-month basis, 22 agreements will expire in 2016, 19 agreements will expire in 2017 and 4 agreements will expire in 2018. The Partnership also has 5 gas treating lease agreements, all of which are on a month-to-month basis. These lease expenses are reflected in Operation and maintenance expense in the Statements of Combined and Consolidated Income.

Other Purchase Obligations and Commitments. In 2006, EOIT entered into a firm capacity agreement with Midcontinent Express Pipeline (MEP), which was effective beginning in 2009 for a primary term of 10 years (subject to possible extension) that gives MEP and its shippers’ access to capacity on EOIT’s system. The quantity of capacity subject to the MEP capacity agreement is currently 275 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,
	2016		2017		2018		2019		2020		Total
	(In millions)
Other purchase obligations and commitments	$	1	$	—	$	—	$	—	$	—	$	1

Legal, Regulatory and Other Matters

The Partnership is involved in 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, 2015

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, Enable Midstream Services) and are taxable at the individual partner level. 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, Enable Midstream Services).

The items comprising income tax expense are as follows:



	Year Ended December 31,
	2015			2014		2013
	(In millions)
Provision for current income taxes
Federal	$	—		$	—	$	1
State	1			1		1
Total provision for current income taxes	1			1		2
Provision (benefit) for deferred income taxes, net
Federal	$	—		—		$	(1,039	)
State	(1		)	1		(155		)
Total provision (benefit) for deferred income taxes, net	(1		)	1		(1,194		)
Total income tax expense (benefit)	$	—		$	2	$	(1,192	)

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



	Year Ended December 31,
	2015			2014			2013
	(In millions)
Income before income taxes	$	(771	)	$	535		$	426
Federal statutory rate	—		%	—		%	35		%
Expected federal income tax expense	—			—			149
Increase in tax expense resulting from:
State income taxes, net of federal income tax	—			2			8
Income not subject to tax	—			—			(103		)
Conversion to partnership	—			—			(1,240		)
Other, net	—			—			(6		)
Total	—			2			(1,341		)
Total income tax expense (benefit)	$	—		$	2		$	(1,192	)
Effective tax rate	—		%	0.4		%	(275.9		)%

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 or liability balances at December 31, 2015 and 2014 related to the Partnership.

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, 2015 and 2014 were as follows:



	December 31,
	2015			2014
	(In millions)
Deferred tax assets:	$	—		$	—
Deferred tax liabilities:
Non-current:
Depreciation	9			9
Other	(1		)	—
Total non-current deferred tax liabilities	8			9
Accumulated deferred income taxes, net	$	8		$	9

Uncertain Income Tax Positions

The Partnership recognizes interest and penalties as a component of income tax expense. There were no unrecognized tax benefits as of December 31, 2015, 2014 and 2013.

Tax Audits and Settlements

CenterPoint Energy’s consolidated federal income tax returns have been audited by the IRS and settled through the 2013 tax year. The federal income tax return of the Partnership has been audited through the 2013 tax year.

Equity Based Compensation

12 Months Ended

Dec. 31, 2015

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, 2015, 2014, and 2013 related to performance units, restricted units, and phantom units for the Partnership's employees and independent directors:



	Year Ended December 31,
	2015		2014		2013
	(In millions)
Performance units	$	3	$	3	$	—
Restricted units	7		10		—
Phantom units	1		2		—
Total compensation expense	$	11	$	15	$	—

Performance Units

The Board of Directors has authorized various grants of performance based phantom units (performance units) 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 target performance, rather than 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 January 1, 2015 through December 31, 2017 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 canceled. 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 one year of daily stock price observations, combined with the average of the two-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.



	2015			2014
Number of units granted	501,474			563,963
Fair value of units granted	$	16.59		$	26.12
Expected price volatility	27.6		%	22.2		%
Risk-free interest rate	0.99		%	0.83		%
Expected life of units (in years)	3.00			3.00

Restricted Units

The Board of Directors has 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.

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, 20% vested on February 1, 2015 and 40% vested on July 15, 2015. Additionally, on April 16, 2014, the Board of Directors granted 150,000 restricted units to the Chief Executive Officer of Enable GP, which 50% vested on May 29, 2015 and 50% was forfeited upon his departure. On April 16, 2014, 137,500 restricted units were granted to the Chief Financial Officer of Enable GP, which vested 45.46% on March 1, 2015 and will vest 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 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.



	2015		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	279,677		304,901
Fair value of restricted units granted	$16.75 - $19.18		$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 vested on the first anniversary of the date of grant. Prior to vesting, each share of restricted units was subject to forfeiture if the recipient ceased 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 were 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 vested 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.



	2015		2014
Phantom units granted	9,817		106,718
Fair value of phantom units granted	$	12.70	$23.16 - $23.70

Other Awards

During 2015, the Board of Directors granted 17,384 common units to the independent directors of Enable GP, for their service as directors, which vested immediately. The fair value of the common units was based on the closing market price of the Partnership’s common unit on the grant date.



	2015
Common units granted	17,384
Fair value of common units granted	$	11.12

Units Outstanding

A summary of the activity for the Partnership's performance units, restricted units, and phantom units as of December 31, 2015 and changes in 2015 are shown in the following table.



	Performance Units					Restricted Stock					Phantom Units					Other Awards
	Number of Units			Weighted Average Grant-Date Fair Value, Per Unit		Number of Units			Weighted Average Grant-Date Fair Value, Per Unit		Number of Units			Weighted Average Grant-Date Fair Value, Per Unit		Number of Units			Weighted Average Grant-Date Fair Value, Per Unit
	(In millions, except unit data)
Units Outstanding at 12/31/2014	552,581			$	26.12	838,068			$	23.47	98,718			$	23.20	—			$	—
Granted⁽¹⁾	501,474			16.59		279,677			17.14		9,817			12.70		17,384			11.12
Vested	(1,254		)	26.12		(400,801		)	22.72		(96,718		)	23.20		(17,384		)	11.12
Forfeited	(238,291		)	24.70		(135,172		)	23.06		(2,000		)	23.16		—			—
Units Outstanding at 12/31/2015	814,510			20.67		581,772			21.04		9,817			12.70		—			—
Aggregate Intrinsic Value of Units Outstanding at 12/31/2015	$	6				$	5				$	—				$	—

_____________________


(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.

A summary of the Partnership's performance, restricted, and phantom units' aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the year ended December 31, 2015 are shown in the following table.



	December 31, 2015
	Performance Units		Restricted Stock		Phantom Units
	(In millions)
Aggregate Intrinsic Value of Units Vested	$	—	$	10	$	2
Fair Value of Units Vested	—		13		2

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, 2015
	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance Units	$	11	2.07
Restricted Units	8		1.74
Phantom Units	—		0.35
Total	$	19

As of December 31, 2015, there were 11,054,681 units available for issuance under the long term incentive plan.

Reportable Segments

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

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 reportable segments are as follows:



Year Ended December 31, 2015	Gathering and Processing			Transportation and Storage ⁽¹⁾			Eliminations			Total
	(In millions)
Revenues ⁽²⁾	$	1,663		$	1,132		$	(377	)	$	2,418
Cost of natural gas and natural gas liquids	908			565			(376		)	1,097
Operation and maintenance, General and administrative	293			230			(1		)	522
Depreciation and amortization	195			123			—			318
Impairments	543			591			—			1,134
Taxes other than income tax	30			29			—			59
Operating (loss) income	$	(306	)	$	(406	)	$	—		$	(712	)
Total assets	$	7,548		$	4,976		$	(1,286	)	$	11,238
Capital expenditures	$	839		$	110		$	—		$	949



Year Ended December 31, 2014	Gathering and Processing		Transportation and Storage ⁽¹⁾		Eliminations			Total
	(In millions)
Revenues ⁽²⁾	$	2,424	$	1,577	$	(634	)	$	3,367
Cost of natural gas and natural gas liquids	1,585		961		(632		)	1,914
Operation and maintenance, General and administrative	297		232		(2		)	527
Depreciation and amortization	160		116		—			276
Impairments	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		Transportation and Storage⁽¹⁾		Eliminations			Total
	(In millions)
Revenues ⁽²⁾	$	1,740	$	1,149	$	(400	)	$	2,489
Cost of natural gas and natural gas liquids	1,075		636		(398		)	1,313
Operation and maintenance, General and administrative	222		209		(2		)	429
Depreciation and amortization	117		95		—			212
Impairments	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

_____________________


(1)	See Note 9 for discussion regarding ownership interest in SESH and related equity earnings included in the Transportation and Storage segment for the years ended December 31, 2015, 2014 and 2013.


(2)	The Partnership had no external customers accounting for 10% or more of revenues in periods shown. See Note 14 for revenues from affiliated companies.

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8981-108599

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e9038-108599

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 33
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8971-108599

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8595-108599

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8380-108599

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8933-108599

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8844-108599

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 35
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8984-108599

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 40
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e9031-108599

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 42
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e9054-108599

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8538-108599

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 29
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8864-108599

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8924-108599

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8906-108599

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2015 and 2014 are as follows:



	Quarters Ended
	March 31, 2015		June 30, 2015		September 30, 2015			December 31, 2015
	(in millions, except per unit data)
Revenues	$	616	$	590	$	646		$	566
Cost of natural gas and natural gas liquids	292		277		287			241
Operating income (loss) ⁽¹⁾	104		93		(975		)	66
Net income (loss)	91		77		(991		)	52
Net income (loss) attributable to Enable Midstream Partners, LP	91		77		(985		)	65

Basic and diluted earnings (loss) per common limited partner unit	$	0.22	$	0.18	$	(2.33	)	$	0.15
Basic and diluted earnings (loss) per subordinated limited partner unit	$	0.21	$	0.18	$	(2.34	)	$	0.15

	Quarters Ended
	March 31, 2014		June 30, 2014		September 30, 2014			December 31, 2014
	(in millions, except per unit data)
Revenues	$	1,002	$	827	$	803		$	735
Cost of natural gas and natural gas liquids	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	$	0.38	$	0.29	$	0.33		$	0.29
Basic and diluted earnings per subordinated limited partner unit	$	—	$	0.29	$	0.33		$	0.29

_____________________

(1) In the third quarter of 2015, the Partnership recorded a $1,087 million impairment to goodwill. For more information see Note 8.

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events Preferred Units On January 28, 2016, the Partnership entered into a Purchase Agreement (the Purchase Agreement) with CenterPoint Energy to issue and sell in a Private Placement an aggregate of 14,520,000 10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units (Preferred Units) for a cash purchase price of $25.00 per Preferred Unit, resulting in total gross proceeds of $363 million. The closing of the Private Placement, which is expected to occur prior to the end of the first quarter of 2016, is subject to the completion of due diligence by the CenterPoint Energy, including the review of the Partnership’s audited financial statements and this Form 10-K, and certain customary closing conditions. In connection with the Private Placement, the Partnership intends to redeem the $363 million of Notes payable—affiliated companies scheduled to mature in 2017 payable to a subsidiary of CenterPoint Energy. Pursuant to the Purchase Agreement, in connection with the closing of the Private Placement, the General Partner will execute a Third Amended and Restated Agreement of Limited Partnership of the Partnership (the Amended Partnership Agreement) to, among other things, authorize and establish the terms of the Preferred Units and the other series of preferred units that are issuable upon conversion of the Preferred Units, in the form attached as an exhibit to the Purchase Agreement. Also, the Partnership has agreed to enter into a Registration Rights Agreement with CenterPoint Energy at the closing of the Private Placement, pursuant to which, among other things, the Partnership will give CenterPoint Energy certain rights to require the Partnership to file and maintain a registration statement with respect to the resale of the Preferred Units and any other series of preferred units or common units representing limited partnership interests in the Partnership that are issuable upon conversion of the Preferred Units. Debt On February 2, 2016, Standard & Poor's Ratings Services lowered its credit rating on the Partnership from an investment grade rating to a noninvestment grade rating. The short-term rating on the Partnership was also reduced from an investment grade rating to a noninvestment grade rating. As a result, we expect our access to our commercial paper program to be limited until these ratings improve. As of February 15, 2016, the Partnership repaid $214 million of commercial paper outstanding at December 31, 2015, and subsequently borrowed $355 million under the Revolving Credit Facility.

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2015
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 services primarily to natural gas producers, utilities and industrial customers. The natural gas gathering and processing assets are located in five 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, 2015, CenterPoint Energy held approximately 55.4% of the limited partner interests in the Partnership, or 94,151,707 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, Enable Midstream Services) 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, Enable Midstream Services). See Note 16 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 June 29, 2015, the financial statements reflect a 49.90% interest in SESH. On June 12, 2015, CenterPoint Energy exercised its put right with respect to a 0.1% interest in SESH. Pursuant to the put right, on June 30, 2015, CenterPoint Energy contributed its remaining 0.1% interest in SESH to the Partnership in exchange for 25,341 common units representing limited partner interests in the Partnership. As of December 31, 2015, the Partnership owned a 50% interest in SESH. See Note 9 for further discussion of SESH. In addition, as of December 31, 2015 and 2014, as a result of the acquisition of Enogex on May 1, 2013, the Partnership held a 50% ownership interest in Atoka. At December 31, 2015 and 2014, the Partnership consolidated Atoka in its Combined and Consolidated Financial Statements as EOIT 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.
Revenue Recognition	Revenue Recognition The Partnership generates the majority of its revenues from midstream energy services, including natural gas gathering, processing, transportation and storage and crude oil gathering. The Partnership performs these services under various contractual arrangements, which include fee-based contract arrangements and arrangements pursuant to which it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. While the Partnership's transactions vary in form, the essential element of each transaction is the use of its assets to transport a product or provide a processed product to a customer. The Partnership reflects revenue as Product sales and Service revenue on the Combined and Consolidated Statements of Income as follows: Product sales: Product sales represent the sale of natural gas, NGLs, crude oil and condensate where the product is purchased and used in connection with providing the Partnership's midstream services. Service revenue: Service revenue represents all other revenue generated as a result of performing the Partnership's midstream services. 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 $17 million and $18 million of deferred revenues on the Consolidated Balance Sheets at December 31, 2015 and 2014, 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 and Natural Gas Liquids Purchases	Natural Gas and Natural Gas Liquids Purchases Cost of natural gas and natural gas liquids represents cost of our natural gas and natural gas liquids purchased exclusive of depreciation, Operation and maintenance and General and administrative expenses and consists primarily of product and fuel costs. 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 natural gas and natural gas liquids, excluding Depreciation and amortization on the Combined and Consolidated Statements of Income.
Operation and Maintenance and General and Administrative Expense	Operation and Maintenance and General and Administrative Expense Operation and maintenance expense represents the cost of our service related revenues and consists primarily of labor expenses, lease costs, utility costs, insurance premiums and repairs and maintenance expenses directly related with the operations of assets. General and administrative expense represents cost incurred to manage the business. This expense includes cost of general corporate services, such as treasury, accounting, legal, information technology and human resources and all other expenses necessary or appropriate to the conduct of business. Any Operation and maintenance expense and General and administrative expense associated with product sales is immaterial.
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, Enable Midstream Services) 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 at least quarterly, 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. There were no material write-downs related to materials and supplies inventory for the year ended December 31, 2015. 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 natural gas 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. For more information, see Note 11. 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 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.
Equity Based Compensation	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.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2015

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 natural gas and natural gas liquids, excluding depreciation and amortization on the Combined and Consolidated Statements of Income.



	December 31,
	2015		2014
	(In millions)
Materials and supplies	$	34	$	39
Natural gas and natural gas liquids inventories	19		24
Total	$	53	$	63

Acquisitions (Tables)

12 Months Ended

Dec. 31, 2015

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

Partnership, with the assistance of a third-party valuation expert, finalized the purchase price allocation as of May 1, 2015.



Purchase price allocation (in millions):
Property, plant and equipment	$	51
Intangibles	10
Goodwill	19
Total	$	80

Pro Forma Information

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



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

Earnings Per Limited Partner Unit (Tables)

12 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

Schedule Of Earnings Per Unit For Common And Subordinated Limited Partner Units

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



	Year Ended December 31,
	2015			2014		2013
	(In millions, except per unit data)
Net (loss) income attributable to Enable Midstream Partners, LP	$	(752	)	$	530	$	1,615
Less general partner interest in net (loss) income	—			—		—
Limited partner interest in net (loss) income attributable to Enable Midstream Partners, LP	$	(752	)	$	530	$	1,615
Net (loss) income allocable to common units	$	(381	)	$	339	$	289
Net (loss) income allocable to subordinated units	(371		)	191		—
Limited partner interest in net (loss) income attributable to Enable Midstream Partners, LP	$	(752	)	$	530	$	289
Basic and diluted weighted average number of outstanding limited partner units
Common units	214			264		390
Subordinated units	208			148		—
Total	422			412		390
Basic and diluted (loss) earnings per limited partner unit
Common units	$	(1.78	)	$	1.29	$	0.74
Subordinated units	$	(1.78	)	$	1.28	$	—

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

12 Months Ended

Dec. 31, 2015

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

December 31, 2015 ⁽¹⁾

February 2, 2016

February 12, 2016

0.318

134

September 30, 2015

November 3, 2015

November 13, 2015

0.318

134

June 30, 2015

August 3, 2015

August 13, 2015

0.316

134

March 31, 2015

May 5, 2015

May 15, 2015

0.3125

132

December 31, 2014

February 4, 2015

February 13, 2015

0.30875

130

September 30, 2014

November 4, 2014

November 14, 2014

0.3025

128

June 30, 2014 ⁽²⁾

August 4, 2014

August 14, 2014

0.2464

104

_____________________


(1)	The board of directors of Enable GP declared this $0.318 per common unit cash distribution on January 22, 2016, to be paid on February 12, 2016, to unitholders of record at the close of business on February 2, 2016.


(2)	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, 2015

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)	2015		2014
		(In millions)
Property, plant and equipment, gross:
Gathering and Processing	33	$	6,478	$	5,560
Transportation and Storage	36	4,444		4,300
Construction work-in-progress		371		604
Total		$	11,293	$	10,464
Accumulated depreciation:
Gathering and Processing		510		343
Transportation and Storage		652		539
Total accumulated depreciation		1,162		882
Property, plant and equipment, net		$	10,131	$	9,582

Intangible Assets, Net (Tables)

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Finite-Lived Intangible Assets

Intangible assets consist of the following:



	December 31,
	2015		2014
	(In millions)
Customer relationships:
Total intangible assets	$	405	$	401
Accumulated amortization	72		45
Net intangible assets	$	333	$	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:



	2016		2017		2018		2019		2020
	(In millions)
Expected amortization of intangible assets	$	27	$	27	$	27	$	27	$	27

Goodwill (Tables)

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

The change in carrying amount of goodwill in each of our reportable segments is as follows:



	Gathering and Processing			Transportation and Storage			Total
	(in millions)
Balance as of December 13, 2013	$	489		$	579		$	1,068

Balance as of December 31, 2014	489			579			1,068
Acquisition of Monarch	19			—			19
Goodwill impairment	(508		)	(579		)	(1,087		)
Balance as of December 31, 2015	$	—		$	—		$	—

Investment in Equity Method Affiliates (Tables)

12 Months Ended

Dec. 31, 2015

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
Interest acquisition of SESH	1
Equity in earnings of equity method affiliate	29
Contributions to equity method affiliate	8
Distributions from equity method affiliate	(42		)
Balance as of December 31, 2015	$	344

Equity in Earnings of Equity Method Affiliates:



	Year Ended December 31,
	2015		2014		2013
	(In millions)
SESH	$	29	$	20	$	15

Distributions from Equity Method Affiliates:



	Year Ended December 31,
	2015		2014		2013
	(In millions)
SESH ⁽¹⁾	$	42	$	23	$	24

_____________________


(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,
	2015			2014
	(In millions)
Balance Sheets:
Current assets	$	45		$	57
Property, plant and equipment, net	1,127			1,127
Total assets	$	1,172		$	1,184
Current liabilities	$	18		$	19
Long-term debt	397			397
Members’ equity	757			768
Total liabilities and members’ equity	$	1,172		$	1,184
Reconciliation:
Investment in SESH	$	344		$	348
Less: Capitalized interest on investment in SESH	(1		)	(2		)
The Partnership’s share of members' equity	$	343		$	346



	Year Ended December 31,
	2015		2014		2013
	(In millions)
Income Statements:
Revenues	$	115	$	108	$	107
Operating income	71		69		66
Net income	57		48		47

Debt (Tables)

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Schedule of Debt

The following table presents the Partnership's outstanding debt as of December 31, 2015 and 2014.



	December 31,
	2015		2014
	(In millions)
Commercial Paper	$	236	$	253
Revolving Credit Facility	310		—
2015 Term Loan Facility	450		—
Notes payable—affiliated companies	363		363
2019 Notes	500		500
2024 Notes	600		600
2044 Notes	550		550
EOIT Senior Notes	250		250
Premium on long-term debt	23		28
Total debt	3,282		2,544
Less amount classified as short-term debt⁽¹⁾	236		253
Less Notes payable—affiliated companies (Note 14)	363		363
Total long-term debt	$	2,683	$	1,928

___________________


(1)	Short-term debt includes $236 million and $253 million of commercial paper as of December 31, 2015 and 2014, respectively.

Schedule of Maturities of Long-term Debt

Maturities of outstanding debt, excluding unamortized premiums, are as follows (in millions):



2016	$	236
2017	363
2018	450
2019	500
2020	560
Thereafter	1,150

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2015

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, 2015 and 2014:



	December 31, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-Term Debt
Long-term notes payable—affiliated companies (Level 2)	$	363	$	350	$	363	$	362
Revolving Credit Facility (Level 2)⁽¹⁾	310		310		—		—
2015 Term Loan Facility (Level 2)	450		450		—		—
EOIT Senior Notes (Level 2)	273		280		279		282
Enable Midstream Partners, LP, 2019, 2024 and 2044 Notes (Level 2)	1,650		1,255		1,649		1,592

___________________


(1)	Borrowing capacity is reduced by our borrowings outstanding under the commercial paper program. $236 million and $253 million of commercial paper was outstanding as of December 31, 2015 and 2014, respectively.

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 as of December 31, 2015 and 2014:



December 31, 2015	Commodity Contracts						Gas Imbalances ⁽¹⁾
	Assets			Liabilities			Assets ⁽²⁾		Liabilities ⁽³⁾
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	17		$	3		$	—	$	—
Significant other observable inputs (Level 2)	10			—			17		$	20
Unobservable inputs (Level 3)	4			—			—		$	—
Total fair value	31			3			17		$	20
Netting adjustments	(3		)	(3		)	—		$	—
Total	$	28		$	—		$	17	$	20



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

______________________

(1)


(2)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $6 million and $4 million at December 31, 2015 and 2014, 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 $5 million and $1 million at December 31, 2015 and 2014, 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.

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation

The following tables provides a reconciliation of changes in the fair value of our Level 3 financial assets between the periods presented.



	Commodity Contracts
	Crude oil (for condensate) financial futures/swaps			Natural gas liquids financial futures/swaps
	(In millions)
Balance as of December 31, 2014	$	5		$	—
Gains included in earnings	12			10
Settlements	(8		)	(6		)
Transfers out of Level 3⁽¹⁾	(9		)	—
Balance as of December 31, 2015	$	—		$	4

______________________


(1)	The Partnership utilizes WTI crude swaps to manage exposure to condensate price risk. As the over-the-counter WTI crude swap is an active market, these derivative instruments will be classified as Level 2 as of December 31, 2015.

Fair Value Inputs, Assets, Quantitative Information



	December 31, 2015
Product Group	Fair Value		Forward Curve Range
	(In millions)		(Per gallon)
Natural gas liquids	$	4	$0.339 - $0.436

Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

As of December 31, 2015 and 2014, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:



	December 31, 2015		December 31, 2014
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas—TBtu⁽¹⁾
Physical purchases/sales	2	51	4	32
Financial fixed futures/swaps	1	37	5	35
Financial basis futures/swaps	4	38	7	54
Crude oil (for condensate)—MBbl⁽²⁾
Financial futures/swaps	—	506	—	274
Natural gas liquids—MBbl⁽³⁾
Financial futures/swaps	75	1,011	—	—

____________________


(1)	As of December 31, 2015, 97.7% of the natural gas contracts have durations of one year or less and 2.3% have durations of more than one year and less than two years. As of December 31, 2014, 91.2% of the natural gas contracts had durations of one year or less, 6.5% had durations of more than one year and less than two years and 2.2% have durations of more than two years.


(2)	As each of December 31, 2015 and 2014, 100% of the crude oil (for condensate) contracts have durations of one year or less.


(3)	As of December 31, 2015, 100% of the natural gas liquid contracts have durations of one year or less.

Schedule of Derivative Assets at Fair Value



		December 31, 2015				December 31, 2014
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	17	$	3	$	34	$	4
Physical purchases/sales	Other Current	1		—		1		—
Crude oil (for condensate)
Financial futures/swaps	Other Current	9		—		5		—
Natural gas liquids
Financial futures/swaps	Other Current	4		—		—		—
Total gross derivatives ⁽¹⁾		$	31	$	3	$	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, 2015 and 2014.

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

The following table presents the effect of derivative instruments on the Partnership’s Consolidated Statements of Income for the years ended December 31, 2015, 2014 and 2013:



	Amounts Recognized in Income
	Year Ended December 31,
	2015			2014		2013
	(In millions)
Natural gas financial futures/swaps gains (losses)	$	26		$	37	$	(1	)
Natural gas physical purchases/sales gains (losses)	(9		)	1		—
Crude oil (for condensate) financial futures/swaps gains (losses)	12			9		—
Natural gas liquids financial futures/swaps gains (losses)	10			2		—
Total	$	39		$	49	$	(1	)

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.

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=56946850&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624163-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41678-113959

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=56946850&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5580258-113959

Reference 6: 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=56946850&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=56946850&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
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=56946850&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=56946850&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

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2015

Schedule of Cash Flow, Supplemental Disclosures

The following table provides information regarding supplemental cash flow information:



	Year Ended December 31,
	2015		2014		2013
	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	85	$	77	$	65
Income taxes (refunds), net	1		1		(9		)
Non-cash transactions:
Accounts payable related to capital expenditures	52		93		43
Issuance of common units upon interest acquisition of SESH (Note 9)	1		161		—
Acquisition of Enogex	—		—		3,788

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2015

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,
	2015		2014		2013
	(In millions)
Gas transportation and storage service revenue — CenterPoint Energy	$	110	$	112	$	108
Natural gas product sales — CenterPoint Energy	7		22		70
Gas transportation and storage service revenue — OGE Energy ⁽¹⁾	37		39		32
Natural gas product sales — OGE Energy⁽¹⁾	8		13		14
Total revenues — affiliated companies	$	162	$	186	$	224

____________________

(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,
	2015		2014		2013
	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	2	$	2	$	4
Cost of natural gas purchases — OGE Energy	15		19		8
Total cost of natural gas purchases — affiliated companies	$	17	$	21	$	12

Schedule of Amounts Charged to Partnership by Related Parties



	Year Ended December 31,
	2015		2014		2013
	(In millions)
Seconded Employee Costs - CenterPoint Energy ⁽¹⁾	$	—	$	138	$	92
Corporate Services - CenterPoint Energy	15		29		38
Seconded Employee Costs - OGE Energy ⁽²⁾	35		105		78
Corporate Services - OGE Energy ⁽²⁾	11		17		18
Total corporate services and seconded employees expense	$	61	$	289	$	226

_________________________


(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 Statements of Income beginning on May 1, 2013.

Commitments and Contingencies Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

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,
	2016		2017		2018		2019		2020		After 2020		Total
	(In millions)
Noncancellable operating leases	$	14	$	5	$	3	$	1	$	—	$	—	$	23

Other Commitments

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



	Year Ended December 31,
	2016		2017		2018		2019		2020		Total
	(In millions)
Other purchase obligations and commitments	$	1	$	—	$	—	$	—	$	—	$	1

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

The items comprising income tax expense are as follows:



	Year Ended December 31,
	2015			2014		2013
	(In millions)
Provision for current income taxes
Federal	$	—		$	—	$	1
State	1			1		1
Total provision for current income taxes	1			1		2
Provision (benefit) for deferred income taxes, net
Federal	$	—		—		$	(1,039	)
State	(1		)	1		(155		)
Total provision (benefit) for deferred income taxes, net	(1		)	1		(1,194		)
Total income tax expense (benefit)	$	—		$	2	$	(1,192	)

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,
	2015			2014			2013
	(In millions)
Income before income taxes	$	(771	)	$	535		$	426
Federal statutory rate	—		%	—		%	35		%
Expected federal income tax expense	—			—			149
Increase in tax expense resulting from:
State income taxes, net of federal income tax	—			2			8
Income not subject to tax	—			—			(103		)
Conversion to partnership	—			—			(1,240		)
Other, net	—			—			(6		)
Total	—			2			(1,341		)
Total income tax expense (benefit)	$	—		$	2		$	(1,192	)
Effective tax rate	—		%	0.4		%	(275.9		)%

Schedule of Deferred Tax Assets and Liabilities

The components of Deferred Income Taxes as of December 31, 2015 and 2014 were as follows:



	December 31,
	2015			2014
	(In millions)
Deferred tax assets:	$	—		$	—
Deferred tax liabilities:
Non-current:
Depreciation	9			9
Other	(1		)	—
Total non-current deferred tax liabilities	8			9
Accumulated deferred income taxes, net	$	8		$	9

Equity Based Compensation (Tables)

12 Months Ended

Dec. 31, 2015

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

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



	Year Ended December 31,
	2015		2014		2013
	(In millions)
Performance units	$	3	$	3	$	—
Restricted units	7		10		—
Phantom units	1		2		—
Total compensation expense	$	11	$	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.



	2015			2014
Number of units granted	501,474			563,963
Fair value of units granted	$	16.59		$	26.12
Expected price volatility	27.6		%	22.2		%
Risk-free interest rate	0.99		%	0.83		%
Expected life of units (in years)	3.00			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.



	2015		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	279,677		304,901
Fair value of restricted units granted	$16.75 - $19.18		$23.56 - $25.50

Phantom Units, Grants in Period And Grant Date Fair Value

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



	2015		2014
Phantom units granted	9,817		106,718
Fair value of phantom units granted	$	12.70	$23.16 - $23.70

Common units, Grants in Period and Grant Date Fair Value

The fair value of the common units was based on the closing market price of the Partnership’s common unit on the grant date.



	2015
Common units granted	17,384
Fair value of common units granted	$	11.12

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, 2015 and changes in 2015 are shown in the following table.



	Performance Units					Restricted Stock					Phantom Units					Other Awards
	Number of Units			Weighted Average Grant-Date Fair Value, Per Unit		Number of Units			Weighted Average Grant-Date Fair Value, Per Unit		Number of Units			Weighted Average Grant-Date Fair Value, Per Unit		Number of Units			Weighted Average Grant-Date Fair Value, Per Unit
	(In millions, except unit data)
Units Outstanding at 12/31/2014	552,581			$	26.12	838,068			$	23.47	98,718			$	23.20	—			$	—
Granted⁽¹⁾	501,474			16.59		279,677			17.14		9,817			12.70		17,384			11.12
Vested	(1,254		)	26.12		(400,801		)	22.72		(96,718		)	23.20		(17,384		)	11.12
Forfeited	(238,291		)	24.70		(135,172		)	23.06		(2,000		)	23.16		—			—
Units Outstanding at 12/31/2015	814,510			20.67		581,772			21.04		9,817			12.70		—			—
Aggregate Intrinsic Value of Units Outstanding at 12/31/2015	$	6				$	5				$	—				$	—

_____________________


(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.



	December 31, 2015
	Performance Units		Restricted Stock		Phantom Units
	(In millions)
Aggregate Intrinsic Value of Units Vested	$	—	$	10	$	2
Fair Value of Units Vested	—		13		2

Schedule of Unrecognized Compensation Cost, Nonvested Awards



	December 31, 2015
	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance Units	$	11	2.07
Restricted Units	8		1.74
Phantom Units	—		0.35
Total	$	19

Reportable Segments (Tables)

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Schedule of Financial Data for Business Segments and Services

Financial data for reportable segments are as follows:



Year Ended December 31, 2015	Gathering and Processing			Transportation and Storage ⁽¹⁾			Eliminations			Total
	(In millions)
Revenues ⁽²⁾	$	1,663		$	1,132		$	(377	)	$	2,418
Cost of natural gas and natural gas liquids	908			565			(376		)	1,097
Operation and maintenance, General and administrative	293			230			(1		)	522
Depreciation and amortization	195			123			—			318
Impairments	543			591			—			1,134
Taxes other than income tax	30			29			—			59
Operating (loss) income	$	(306	)	$	(406	)	$	—		$	(712	)
Total assets	$	7,548		$	4,976		$	(1,286	)	$	11,238
Capital expenditures	$	839		$	110		$	—		$	949



Year Ended December 31, 2014	Gathering and Processing		Transportation and Storage ⁽¹⁾		Eliminations			Total
	(In millions)
Revenues ⁽²⁾	$	2,424	$	1,577	$	(634	)	$	3,367
Cost of natural gas and natural gas liquids	1,585		961		(632		)	1,914
Operation and maintenance, General and administrative	297		232		(2		)	527
Depreciation and amortization	160		116		—			276
Impairments	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		Transportation and Storage⁽¹⁾		Eliminations			Total
	(In millions)
Revenues ⁽²⁾	$	1,740	$	1,149	$	(400	)	$	2,489
Cost of natural gas and natural gas liquids	1,075		636		(398		)	1,313
Operation and maintenance, General and administrative	222		209		(2		)	429
Depreciation and amortization	117		95		—			212
Impairments	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

_____________________


(1)	See Note 9 for discussion regarding ownership interest in SESH and related equity earnings included in the Transportation and Storage segment for the years ended December 31, 2015, 2014 and 2013.


(2)	The Partnership had no external customers accounting for 10% or more of revenues in periods shown. See Note 14 for revenues from affiliated companies.

Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

Summarized unaudited quarterly financial data for 2015 and 2014 are as follows:



	Quarters Ended
	March 31, 2015		June 30, 2015		September 30, 2015			December 31, 2015
	(in millions, except per unit data)
Revenues	$	616	$	590	$	646		$	566
Cost of natural gas and natural gas liquids	292		277		287			241
Operating income (loss) ⁽¹⁾	104		93		(975		)	66
Net income (loss)	91		77		(991		)	52
Net income (loss) attributable to Enable Midstream Partners, LP	91		77		(985		)	65

Basic and diluted earnings (loss) per common limited partner unit	$	0.22	$	0.18	$	(2.33	)	$	0.15
Basic and diluted earnings (loss) per subordinated limited partner unit	$	0.21	$	0.18	$	(2.34	)	$	0.15

	Quarters Ended
	March 31, 2014		June 30, 2014		September 30, 2014			December 31, 2014
	(in millions, except per unit data)
Revenues	$	1,002	$	827	$	803		$	735
Cost of natural gas and natural gas liquids	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	$	0.38	$	0.29	$	0.33		$	0.29
Basic and diluted earnings per subordinated limited partner unit	$	—	$	0.29	$	0.33		$	0.29

_____________________

(1) In the third quarter of 2015, the Partnership recorded a $1,087 million impairment to goodwill. For more information see Note 8.

Summary of Significant Accounting Policies - Narrative (Details)
$ / shares in Units, $ in Millions

3 Months Ended

12 Months Ended

13 Months Ended

Apr. 16, 2014

USD ($)

$ / shares

Mar. 25, 2014

May 01, 2013

USD ($)

Dec. 31, 2015

USD ($)

state

Sep. 30, 2015

USD ($)

Jun. 30, 2015

USD ($)

Mar. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Sep. 30, 2014

USD ($)

Jun. 30, 2014

USD ($)

Mar. 31, 2014

USD ($)

Dec. 31, 2015

USD ($)

state

segment

Dec. 31, 2014

USD ($)

Dec. 31, 2013

USD ($)

Jun. 29, 2015

May 29, 2014

May 02, 2013

Apr. 30, 2013

Dec. 31, 2012

USD ($)

Number of reportable segments | segment

Number of states in which natural gas gathering and processing assets are located | state

Minimum percentage of vote required by all unitholders

75.00%

Income tax benefit

$ 1,240

$ 0

$ 2

$ (1,192)

Deferred revenues

$ 17

$ 18

Cash and cash equivalents

566

$ 646

$ 590

$ 616

735

$ 803

$ 827

$ 1,002

2,418

^[1]

3,367

^[1]

2,489

^[1]

Environmental exit costs

108

$ 0

Allowance for doubtful accounts receivable

Regulatory liabilities

$ 18

$ 16

AFUDC, capitalized interest

Conversion ratio

1.279082616

Materials and Supplies

Write down of materials and supplies inventory

Natural gas

Write down of materials and supplies inventory

$ 13

$ 4

Percentage share of management rights

50.00%

Percentage share of incentive distribution rights

40.00%

Percentage share of management rights

55.40%

Income tax benefit

$ 1,240

OGE Energy

50.00%

Percentage share of incentive distribution rights

60.00%

26.30%

Enogex

Ownership percentage

100.00%

Atoka

50.00%

Limited partner ownership interest, exercisable as early as May 2014

50.00%

49.90%

Ownership percentage

50.00%

24.95%

SESH | CenterPoint

Distributed ownership percentage

25.05%

Volume of natural gas liquids | Customer Concentration Risk

Concentration risk percentage

18.00%

21.00%

30.00%

Total revenue | Customer Concentration Risk

Concentration risk percentage

4.00%

7.00%

9.00%

Other Revenue | Customer Concentration Risk

$ 108

$ 235

$ 232

Concentration risk percentage

0.00%

Common Units | CenterPoint

Common Units | OGE Energy

94,151,707

Common units issued during period (in shares) | shares

42,832,291

Common Units | IPO

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

Period of demand fees for expiring transportation and storage contracts

3 years

Common Units | IPO | CenterPoint

Conversion of stock, common units converted (in shares) | shares

139,704,916

Common Units | IPO | OGE Energy

Conversion of stock, common units converted (in shares) | shares

68,150,514

Common Units | Over-Allotment Option

Common units issued during period (in shares) | shares

3,750,000

Subordinated Units | CenterPoint

Subordinated Units | OGE Energy

139,704,916

Limited partner ownership interest, exercisable as early as May 2015

68,150,514

Put Option | SESH | SESH

0.10%

Limited partner units that may be issued, exercisable as early as May 2015 | shares

25,341

[1]	The Partnership had no external customers accounting for 10% or more of revenues in periods shown. See Note 14 for revenues from affiliated companies.

Summary of Significant Accounting Policies - Inventory (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Materials and supplies	$ 34	$ 39
Natural gas and natural gas liquids inventories	19	24
Total	$ 53	$ 63

New Accounting Pronouncements (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Accounting Changes and Error Corrections [Abstract]
Unamortized debt expense	$ 12	$ 13

Acquisitions - Schedule of Assets and Liabilities Assumed (Details)
hp in Thousands

3 Months Ended

4 Months Ended

8 Months Ended

12 Months Ended

May 01, 2015

USD ($)

May 01, 2013

USD ($)

Dec. 31, 2015

USD ($)

Sep. 30, 2015

USD ($)

Jun. 30, 2015

USD ($)

Mar. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Sep. 30, 2014

USD ($)

Jun. 30, 2014

USD ($)

Mar. 31, 2014

USD ($)

Apr. 30, 2013

USD ($)

Dec. 31, 2013

USD ($)

Dec. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Dec. 31, 2013

USD ($)

Apr. 22, 2015

Assets

Business Combination, Revenues And Net Income [Abstract]

$ 0

$ 1,068,000,000

$ 0

$ 1,068,000,000

566,000,000

$ 646,000,000

$ 590,000,000

$ 616,000,000

735,000,000

$ 803,000,000

$ 827,000,000

$ 1,002,000,000

2,418,000,000

^[1]

3,367,000,000

^[1]

2,489,000,000

^[1]

66,000,000

^[2]

(975,000,000)

^[2]

93,000,000

^[2]

104,000,000

^[2]

134,000,000

152,000,000

138,000,000

162,000,000

(712,000,000)

586,000,000

469,000,000

Net (loss) income attributable to Enable Midstream Partners, LP

$ 52,000,000

$ (991,000,000)

$ 77,000,000

$ 91,000,000

$ 123,000,000

$ 139,000,000

$ 121,000,000

$ 150,000,000

$ 1,326,000,000

292,000,000

(771,000,000)

533,000,000

1,618,000,000

(752,000,000)

$ 530,000,000

$ 1,615,000,000

Common Units | CenterPoint | Partners' Capital

Common Units | OGE Energy | Partners' Capital

227,508,825

Common Units | ArcLight | Partners' Capital

110,982,805

General and Administrative Expense

51,527,730

Acquisition costs associated with the transaction

$ 1,000,000

Customer Relationships

Weighted average useful life

15 years

Gas Gathering and Processing Equipment

Length of gathering pipeline (miles) | mi

106

Compression horsepower | hp

Aggregate purchase price

$ 80,000,000

Monarch Natural Gas, LLC

Assets

Property, plant and equipment

51,000,000

19,000,000

Other intangible assets

10,000,000

Total

$ 80,000,000

Enogex

Percentage of interest acquired

100.00%

Assets

Current Assets

$ 192,000,000

Property, plant and equipment

3,919,000,000

439,000,000

Other intangible assets

401,000,000

Other assets

21,000,000

Less: Noncontrolling interest at fair value

4,972,000,000

Liabilities

393,000,000

745,000,000

20,000,000

1,158,000,000

26,000,000

Fair value of consideration transferred

$ 3,788,000,000

Business Combination, Revenues And Net Income [Abstract]

1,406,000,000

92,000,000

Net (loss) income attributable to Enable Midstream Partners, LP

77,000,000

$ 74,000,000

Enogex | Weighted Average

Weighted Average Useful Lives (Years)

32 years

[1]	The Partnership had no external customers accounting for 10% or more of revenues in periods shown. See Note 14 for revenues from affiliated companies.
[2]	In the third quarter of 2015, the Partnership recorded a $1,087 million impairment to goodwill. For more information see Note 8.

Acquisitions - 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, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Dilutive effect of unit-based awards (in dollars per unit)									$ 0.01
Net (loss) income attributable to Enable Midstream Partners, LP									$ (752)	$ 530	$ 1,615
Less general partner interest in net (loss) income									0	0	0
Limited partner interest in net (loss) income attributable to Enable Midstream Partners, LP									(752)	530	1,615
Net (loss) income attributable to Enable Midstream Partners, LP	$ 65	$ (985)	$ 77	$ 91	$ 122	$ 139	$ 120	$ 149	$ (752)	$ 530	$ 289
Basic and diluted weighted average number of outstanding limited partner units
Basic and diluted weighted average number of outstanding limited partner units (in units)									422	412	390
Common Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net (loss) income attributable to Enable Midstream Partners, LP									$ (381)	$ 339	$ 289
Basic and diluted weighted average number of outstanding limited partner units
Basic and diluted weighted average number of outstanding limited partner units (in units)									214	264	390
Basic and diluted (loss) earnings per limited partner unit
Basic and diluted earnings per unit (in dollars per unit)	$ 0.15	$ (2.33)	$ 0.18	$ 0.22	$ 0.29	$ 0.33	$ 0.29	$ 0.38	$ (1.78)	$ 1.29	$ 0.74
Subordinated Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net (loss) income attributable to Enable Midstream Partners, LP									$ (371)	$ 191	$ 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)									208	148	0
Basic and diluted (loss) earnings per limited partner unit
Basic and diluted earnings per unit (in dollars per unit)	$ 0.15	$ (2.34)	$ 0.18	$ 0.21	$ 0.29	$ 0.33	$ 0.29	$ 0.00	$ (1.78)	$ 1.28	$ 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, 2015	Dec. 31, 2014	Dec. 31, 2013	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	$ 0	$ (434)
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 - 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, 2015
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
Incentive distribution, distribution per unit								$ 0.330625
Minimum quarterly distribution per common unit								$ 0.2875
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%

Enable Midstream Partners, LP Parent Net Equity and Partners' Capital - Cash Distributions (Details) - USD ($)

Feb. 12, 2016

Feb. 02, 2016

Jan. 22, 2016

Nov. 13, 2015

Nov. 03, 2015

Aug. 13, 2015

Aug. 03, 2015

May 15, 2015

May 05, 2015

Feb. 13, 2015

Feb. 04, 2015

Nov. 14, 2014

Nov. 04, 2014

Aug. 14, 2014

^[1]

Aug. 05, 2014

^[1]

Distribution Made to Limited Partner [Line Items]

Record Date

Nov. 03, 2015

Aug. 03, 2015

May 05, 2015

Feb. 04, 2015

Nov. 04, 2014

Aug. 04, 2014

Payment Date

Nov. 13, 2015

Aug. 13, 2015

May 15, 2015

Feb. 13, 2015

Nov. 14, 2014

Aug. 14, 2014

Cash Distribution

Distribution Made to Limited Partner [Line Items]

Per Unit Distribution, paid (in dollars per unit)

$ 0.318

$ 0.316

$ 0.3125

$ 0.30875

$ 0.3025

$ 0.2464

Total Cash Distribution

$ 134,000,000

$ 132,000,000

$ 130,000,000

$ 128,000,000

$ 104,000,000

Subsequent Event

Distribution Made to Limited Partner [Line Items]

Record Date

^[2]

Feb. 02, 2016

Payment Date

^[2]

Feb. 12, 2016

Subsequent Event | Cash Distribution

Distribution Made to Limited Partner [Line Items]

Per Unit Distribution, paid (in dollars per unit)

^[2]

$ 0.318

Total Cash Distribution

^[2]

$ 134,000,000

Common unit cash distribution declared per unit

^[2]

$ 0.318

[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.
[2]	The board of directors of Enable GP declared this $0.318 per common unit cash distribution on January 22, 2016, to be paid on February 12, 2016, to unitholders of record at the close of business on February 2, 2016.

Property, Plant and Equipment - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 11,293	$ 10,464
Less accumulated depreciation and amortization	1,162	882
Property, plant and equipment, net	10,131	9,582
Depreciation	$ 291	249	$ 194
Gathering and Processing
Property, Plant and Equipment [Line Items]
Weighted Average Useful Lives (Years)	33 years
Property, plant and equipment, gross	$ 6,478	5,560
Less accumulated depreciation and amortization	$ 510	343
Transportation and Storage
Property, Plant and Equipment [Line Items]
Weighted Average Useful Lives (Years)	36 years
Property, plant and equipment, gross	$ 4,444	4,300
Less accumulated depreciation and amortization	652	539
Construction work-in-progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 371	$ 604

Intangible Assets, Net - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 27	$ 27	$ 18
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
Expected amortization of intangible assets, 2020	27
Customer Relationships
Finite-Lived Intangible Assets [Line Items]
Total intangible assets	405	401
Accumulated amortization	72	45
Net intangible assets	$ 333	$ 356
Weighted average useful life	15 years

Goodwill - Narrative (Details) - USD ($)	3 Months Ended	12 Months Ended
Goodwill - Narrative (Details) - USD ($)	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Goodwill [Roll Forward]
Goodwill		$ 1,068,000,000	$ 1,068,000,000
Acquisition of Monarch		19,000,000
Goodwill impairment	$ 1,087,000,000	1,087,000,000	0	$ 0
Goodwill		0	1,068,000,000	1,068,000,000
Gathering and Processing
Goodwill [Roll Forward]
Goodwill		489,000,000	489,000,000
Acquisition of Monarch		19,000,000
Goodwill impairment		508,000,000
Goodwill		0	489,000,000	489,000,000
Transportation and Storage
Goodwill [Roll Forward]
Goodwill		579,000,000	579,000,000
Acquisition of Monarch		0
Goodwill impairment		579,000,000
Goodwill		$ 0	579,000,000	579,000,000
Enable Oklahoma
Goodwill [Roll Forward]
Goodwill			$ 438,000,000
Goodwill				$ 438,000,000

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 ($)

May 14, 2014

USD ($)

Feb. 14, 2014

USD ($)

Nov. 14, 2013

USD ($)

Aug. 14, 2013

USD ($)

May 01, 2013

Apr. 30, 2013

USD ($)

Sep. 30, 2014

USD ($)

Apr. 30, 2013

USD ($)

Dec. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Dec. 31, 2013

USD ($)

Jun. 29, 2015

May 29, 2014

Jun. 12, 2015

USD ($)

Distribution to limited partner

$ 22,000,000

$ 155,000,000

$ 114,000,000

$ 120,000,000

$ 61,000,000

$ 289,000,000

Interstate natural gas pipeline length (in miles) | mi

Ownership percentage

50.00%

286

Limited partner ownership interest, exercisable as early as May 2014

24.95%

Fair value of common units

$ 1,000,000

50.00%

49.90%

Percentage distributions

50.00%

SESH | Shared Operations Service Agreements | Equity Method Investee

^[1]

$ 42,000,000

$ 23,000,000

$ 24,000,000

Amount billed to SESH associated with service agreements

12,000,000

13,000,000

15,000,000

Investments in Equity Method Affiliates | SESH

Distribution to limited partner

$ 7,000,000

$ 198,000,000

42,000,000

23,000,000

24,000,000

$ 196,000,000

Investment in equity method investment

$ 187,000,000

Investments in Equity Method Affiliates | Senior Notes | SESH

Investments in Equity Method Affiliates | Senior Notes Due August 2014 | Senior Notes | SESH

400,000,000

Return of Special Distribution | Investments in Equity Method Affiliates | SESH

$ 375,000,000

Investment in equity method investment

$ 187,000,000

Distribution to limited partner

$ 1,000,000

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

SESH | Put Option | SESH

Limited partner ownership interest, exercisable as early as May 2015

0.10%

Limited partner units that may be issued, exercisable as early as May 2015 | shares

25,341

Distributed ownership percentage

55.40%

CenterPoint | SESH

25.05%

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

Investment in Equity Method Affiliates - Schedule of Investments (Details) - USD ($)
$ in Millions

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

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Investments in and Advances to Affiliates, at Fair Value [Roll Forward]

Balance beginning of period

$ 348

Net distributions to CenterPoint Energy prior to formation

$ (22)

$ (155)

$ (114)

$ (120)

$ (61)

$ (289)

Return of investment from SESH refinancing

$ 20

$ 15

(8)

(198)

Contributions to equity method affiliate

464

Balance end of period

344

348

Equity in Earnings of Equity Method Affiliates:

Investments in and Advances to Affiliates, at Fair Value [Roll Forward]

Balance beginning of period

348

Distributions from equity method affiliate

^[1]

(42)

(23)

(24)

Balance end of period

344

348

Distributions from Equity Method Affiliates:

^[1]

115

108

107

Other Income (Expense) | SESH

Investments in and Advances to Affiliates, at Fair Value [Roll Forward]

Equity in Earnings of Equity Method Affiliates:

Investments in Equity Method Affiliates | SESH

Investments in and Advances to Affiliates, at Fair Value [Roll Forward]

Balance beginning of period

$ 405

348

198

405

Net distributions to CenterPoint Energy prior to formation

(196)

Capitalized interest on investment in SESH

(2)

Distributions from equity method affiliate

$ (7)

$ (198)

(42)

(23)

(24)

Interest acquisition of SESH

161

Additional investment in SESH

187

Contributions to equity method affiliate

Balance end of period

344

348

198

Equity in Earnings of Equity Method Affiliates:

Distributions from Equity Method Affiliates:

Special Distribution | Investments in Equity Method Affiliates | SESH

$ 7

$ 198

$ 42

$ 24

Investments in and Advances to Affiliates, at Fair Value [Roll Forward]

Return of investment from SESH refinancing

$ (198)

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

Investment in Equity Method Affiliates - Financial Information of SESH (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Investment in SESH	$ 344	$ 348
SESH
Schedule of Equity Method Investments [Line Items]
Current assets	45	57
Property, plant and equipment, net	1,127	1,127
Total assets	1,172	1,184
Current liabilities	18	19
Long-term debt	397	397
Members’ equity	757	768
Total liabilities and members’ equity	1,172	1,184
Investment in SESH	344	348
Less: Capitalized interest on investment in SESH	(1)	(2)
The Partnership’s share of members' equity	$ 343	$ 346

Debt - Narrative (Details)

12 Months Ended

Dec. 29, 2015

USD ($)

Oct. 09, 2015

Jul. 31, 2015

USD ($)

time

May 27, 2014

USD ($)

Dec. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Jun. 18, 2015

USD ($)

Jan. 31, 2014

USD ($)

May 01, 2013

USD ($)

Notes payable, related parties

$ 3,282,000,000

$ 2,544,000,000

363,000,000

Less amount classified as short-term debt

^[1]

236,000,000

253,000,000

Total long-term debt

2,683,000,000

1,928,000,000

Carrying value

236,000,000

253,000,000

Commercial paper, authorized

$ 1,400,000,000

Other Assets

Revolving Credit Facility

Unamortized debt expense

18,000,000

17,000,000

Maximum borrowing capacity

310,000,000

$ 1,750,000,000

Letters of credit principal advances

310,000,000

Letters of credit outstanding amount

$ 3,000,000

Weighted average interest rate

1.85%

Unused capacity, commitment fee percentage

0.20%

Consolidated debt to EBITDA ratio

5.00

Consideration transferred, threshold for debt covenant ratio

$ 25,000,000

Covenant, acceleration of indebtedness, threshold amount

100,000,000

Covenant, acceleration of indebtedness, nonpayment of uninsured money judgments, threshold amount

$ 100,000,000

Revolving Credit Facility | Maximum

Consolidated debt to EBITDA ratio

5.50

Senior unsecured 2013 Term Loan Facility

Maximum borrowing capacity

$ 1,050,000,000

Term Loan Facility

Losses on extinguishment of debt

$ 450,000,000

4,000,000

Term Loan Facility | LIBOR

Basis spread on variable rate

1.50%

Enable Oklahoma Term Loan | Term Loan Facility

Maximum borrowing capacity

$ 250,000,000

Commercial Paper

Weighted average interest rate

$ 236,000,000

253,000,000

1.63%

Senior Notes

Proceeds from issuance of debt

$ 1,630,000,000

Senior Notes | 2.400% Senior Notes

$ 500,000,000

500,000,000

$ 500,000,000

Senior Notes | 3.900% Senior Notes

2.40%

600,000,000

$ 600,000,000

Senior Notes | 5.000% Senior Notes

3.90%

550,000,000

$ 550,000,000

Senior Notes | 6.25% Senior Notes

5.00%

250,000,000

Unamortized premium

23,000,000

28,000,000

$ 250,000,000

Senior Notes | 6.875% Senior Notes

6.25%

Effective percentage

5.60%

$ 200,000,000

Senior Notes | Senior Notes including 2019 Notes, 2024 Notes, and 2044 Notes

6.875%

Additional interest rate percentage

0.25%

Period for additional interest rate percentage

90 days

Amount of additional interest expense

$ 1,000,000

Unsecured Debt | 2015 Term Loan Facility

Weighted average interest rate

1.80%

Term loan facility, term

3 years

Principal amount of term loan facility

$ 450,000,000

Number of times option may be exercised | time

Additional term of loan

1 year

Minimum prepayment amount

$ 1,000,000

Amount of multiple to prepay the amount outstanding

$ 500,000

Unsecured Debt | 2015 Term Loan Facility | LIBOR

Basis spread on variable rate

1.375%

[1]	Short-term debt includes $236 million and $253 million of commercial paper as of December 31, 2015 and 2014, respectively.

Debt - Maturities of Long Term Debt (Details) $ in Millions	Dec. 31, 2015 USD ($)
Debt Disclosure [Abstract]
Long-term debt maturities in 2016	$ 236
Long-term debt maturities in 2017	363
Long-term debt maturities in 2018	450
Long-term debt maturities in 2019	500
Long-term debt maturities in 2020	560
Thereafter	$ 1,150

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

Dec. 31, 2015

Dec. 31, 2014

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

Fuel reserves for under retained fuel due from shippers

$ 6

$ 4

Fuel reserves for over retained fuel due from shippers

Commodity Contracts | Recurring Measurement

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

Derivative asset, fair value, before netting adjustments

Derivative liability, fair value, before netting adjustments

Derivative asset, netting adjustment

(3)

(4)

Derivative liability, netting adjustment

(3)

(4)

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]

Commodity Contracts | Recurring Measurement | Significant other observable inputs (Level 2)

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

Commodity Contracts | Recurring Measurement | Unobservable inputs (Level 3)

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

Gas Imbalances | Recurring Measurement

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

Derivative asset, fair value, before netting adjustments

^[1],[2]

Derivative liability, fair value, before netting adjustments

^[2],[3]

Derivative asset, netting adjustment

^[1],[2]

Derivative liability, netting adjustment

^[2],[3]

^[1],[2]

Gas Imbalances | Recurring Measurement | Quoted market prices in active market for identical assets (Level 1)

^[2],[3]

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

^[1],[2]

Gas Imbalances | Recurring Measurement | Significant other observable inputs (Level 2)

^[2],[3]

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

^[1],[2]

Gas Imbalances | Recurring Measurement | Unobservable inputs (Level 3)

^[2],[3]

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

^[1],[2]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

^[2],[3]

$ 0

[1]	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $6 million and $4 million at December 31, 2015 and 2014, 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.
[2]	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 EOIT 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, 2015 and 2014.
[3]	Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $5 million and $1 million at December 31, 2015 and 2014, 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.

Fair Value Measurements - Estimated Fair Value of Financial Instruments and Non-Financial Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Fair Value, Measurements, Nonrecurring | Transportation and Storage | Pipelines

$ 3,282

$ 2,544

Carrying value

236

253

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Impairment of jurisdictional pipelines

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]

Significant other observable inputs (Level 2) | Revolving Credit Facility (Level 2)

350

362

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Significant other observable inputs (Level 2) | 2015 Term Loan Facility (Level 2)

^[1]

310

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Significant other observable inputs (Level 2) | Enable Oklahoma Senior Notes (Level 2)

450

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Significant other observable inputs (Level 2) | Enable Midstream Partners, LP, 2019, 2024 and 2044 Notes (Level 2)

280

282

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Unobservable inputs (Level 3) | Fair Value, Measurements, Nonrecurring | Gathering and Processing | Service Star Assets | Income Approach Valuation Technique

1,255

1,592

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Unobservable inputs (Level 3) | Fair Value, Measurements, Nonrecurring | Gathering and Processing | Atoka Assets | Income Approach Valuation Technique

$ 12

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Write down of intangibles

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Write down of property plant and equipment

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Carrying Amount | Significant other observable inputs (Level 2) | Long-term notes payable—affiliated companies (Level 2) | Affiliated Companies

$ 2

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Carrying Amount | Significant other observable inputs (Level 2) | Revolving Credit Facility (Level 2)

363

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Carrying Amount | Significant other observable inputs (Level 2) | 2015 Term Loan Facility (Level 2)

^[1]

310

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Carrying Amount | Significant other observable inputs (Level 2) | Enable Oklahoma Senior Notes (Level 2)

450

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Carrying Amount | Significant other observable inputs (Level 2) | Enable Midstream Partners, LP, 2019, 2024 and 2044 Notes (Level 2)

273

279

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Crude oil (for condensate) financial futures/swaps

$ 1,650

$ 1,649

[1]	Borrowing capacity is reduced by our borrowings outstanding under the commercial paper program. $236 million and $253 million of commercial paper was outstanding as of December 31, 2015 and 2014, respectively.

Fair Value Measurements - Schedule of Changes in Fair Values of Level 3 Financial Assets (Details) - Commodity Contracts - Derivative Financial Instruments, Assets
$ in Millions

12 Months Ended

Dec. 31, 2015

USD ($)

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

Beginning Balance

$ 5

Settlements

Gains included in earnings

(8)

Transfers out of Level 3

(9)

^[1]

Ending Balance

Natural gas liquids financial futures/swaps

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

Beginning Balance

Settlements

Gains included in earnings

(6)

Transfers out of Level 3

^[1]

Ending Balance

$ 4

[1]	The Partnership utilizes WTI crude swaps to manage exposure to condensate price risk. As the over-the-counter WTI crude swap is an active market, these derivative instruments will be classified as Level 2 as of December 31, 2015.

Fair Value Measurements - Schedule of Quantitative Information on Level 3 Fair Value Inputs (Details) - Commodity Contracts - Natural gas liquids financial futures/swaps - Derivative Financial Instruments, Assets - Market Approach Valuation Technique - Unobservable inputs (Level 3) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) $ / gal
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value \| $	$ 4
Minimum
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Forward Curve Range (Per gallon)	0.339
Maximum
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Forward Curve Range (Per gallon)	0.436

Derivative Instruments and Hedging Activities - Narrative (Details) bbl in Thousands, MMBTU in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) MMBTU bbl	Dec. 31, 2014 USD ($) MMBTU bbl
Derivative [Line Items]
Designated cash flow hedges \| $	$ 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	97.70%	91.20%
Percent of contracts with durations of more than one year and less than two years	2.30%	6.50%
Percent of contracts having a duration of more than two years		2.20%
Not Designated as Hedging Instrument \| Natural gas \| Physical \| Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	2	4
Not Designated as Hedging Instrument \| Natural gas \| Physical \| Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	51	32
Not Designated as Hedging Instrument \| Natural gas \| Financial fixed futures/swaps \| Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	1	5
Not Designated as Hedging Instrument \| Natural gas \| Financial fixed futures/swaps \| Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	37	35
Not Designated as Hedging Instrument \| Natural gas \| Financial basis futures/swaps \| Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	4	7
Not Designated as Hedging Instrument \| Natural gas \| Financial basis futures/swaps \| Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	38	54
Not Designated as Hedging Instrument \| Crude oil (for condensate)
Derivative [Line Items]
Percent of contract with durations of one year or less	100.00%
Not Designated as Hedging Instrument \| Crude oil (for condensate) \| Financial futures/swaps \| Purchases
Derivative [Line Items]
Derivative, gross notional volume (MMbl) \| bbl	0	0
Not Designated as Hedging Instrument \| Crude oil (for condensate) \| Financial futures/swaps \| Sales
Derivative [Line Items]
Derivative, gross notional volume (MMbl) \| bbl	506	274
Not Designated as Hedging Instrument \| Volume of natural gas liquids
Derivative [Line Items]
Percent of contract with durations of one year or less	100.00%
Not Designated as Hedging Instrument \| Volume of natural gas liquids \| Financial futures/swaps \| Purchases
Derivative [Line Items]
Derivative, gross notional volume (MMbl) \| bbl	75	0
Not Designated as Hedging Instrument \| Volume of natural gas liquids \| Financial futures/swaps \| Sales
Derivative [Line Items]
Derivative, gross notional volume (MMbl) \| bbl	1,011	0

Derivative Instruments and Hedging Activities - Balance Sheet Location (Details) - Not Designated as Hedging Instrument - USD ($)
$ in Millions

Dec. 31, 2015

Dec. 31, 2014

Natural gas

^[1]

$ 31

$ 40

Natural gas | Financial futures/swaps | Other Current

^[1]

Natural gas | Financial futures/swaps | Other Current

Natural gas | Physical purchases/sales | Other Current

Natural gas | Physical purchases/sales | Other Current

Crude oil (for condensate) | Financial futures/swaps | Other Current

Crude oil (for condensate) | Financial futures/swaps | Other Current

Natural gas liquids financial futures/swaps | Financial futures/swaps | Other Current

Natural gas liquids financial futures/swaps | Financial futures/swaps | Other Current

$ 0

[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, 2015 and 2014.

Derivative Instruments and Hedging Activities - Amounts Recognized in Income (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	$ 39,000,000	$ 49,000,000	$ (1,000,000)
Cash collateral required if ratings are lowered	0
Natural gas \| Physical purchases/sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	26,000,000	37,000,000	(1,000,000)
Natural gas \| Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	(9,000,000)	1,000,000	0
Crude oil (for condensate) \| Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	12,000,000	9,000,000	0
Natural gas liquids financial futures/swaps \| Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	$ 10,000,000	$ 2,000,000	$ 0

Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]
Interest, net of capitalized interest	$ 85	$ 77	$ 65
Income taxes (refunds), net	1	1	(9)
Accounts payable related to capital expenditures	52	93	43
Issuance of common units upon interest acquisition of SESH (Note 9)	1	161	0
Acquisition of Enogex	$ 0	$ 0	$ 3,788

Related Party Transactions - Narrative (Details)	12 Months Ended
Related Party Transactions - Narrative (Details)	Dec. 31, 2015 USD ($) mi	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Related Party Transaction [Line Items]
Partnership's revenues from affiliated companies as a percent of total revenues	7.00%	6.00%	9.00%
Charges to the Partnership by affiliates	$ 61,000,000	$ 289,000,000	$ 226,000,000
Notes payable, related parties	363,000,000	363,000,000
Notes payable—affiliated companies	363,000,000	363,000,000
Interest income—affiliated companies	0	0	9,000,000
Remaining net book value of pipeline segment	$ 10,131,000,000	9,582,000,000
Pipelines
Related Party Transaction [Line Items]
Number of miles of new pipeline constructed \| mi	28.5
Number of miles of existing pipeline segments abandoned \| mi	34.2
CenterPoint and OGE Energy
Related Party Transaction [Line Items]
Period notice of termination for reimbursements for all employee costs	90 days
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 2016	$ 6,000,000
Expense reimbursement in 2017	6,000,000
Expense reimbursement in 2018	5,000,000
Expense reimbursement in 2019	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	11,000,000
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	8,000,000	34,000,000
Interest income—affiliated companies	0		$ 9,000,000
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	$ 15,000,000
EGT \| Pipeline sold to CenterPoint Energy's Arkansas LDC \| Pipelines
Related Party Transaction [Line Items]
Number of miles of pipeline segment sold \| mi	12.4
Remaining net book value of pipeline segment	$ 1,000,000
EGT \| Amount Reimbursed for Costs Incurred in Connecting New Pipeline Segment \| Pipelines
Related Party Transaction [Line Items]
Amount of reimbursement	$ 7,000,000

Related Party Activity (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Cost of goods sold from affiliate

$ 162

$ 186

$ 224

289

226

Cost of goods sold from affiliate

CenterPoint | Gas Transportation and Storage

110

112

108

CenterPoint | Gas Sales

CenterPoint | Seconded Employee Costs

CenterPoint | Corporate Services

^[1]

138

Cost of goods sold from affiliate

OGE Energy

OGE Energy | Gas Transportation and Storage

^[2]

OGE Energy | Gas Sales

OGE Energy | Seconded Employee Costs

^[2]

OGE Energy | Corporate Services

^[3]

105

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

^[3]

$ 11

$ 17

$ 18

[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]	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 Statements 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.
[3]	Corporate services and seconded employee expenses from OGE Energy are reflected in the Combined and Consolidated Statements of Income beginning on May 1, 2013.

Commitments and Contingencies - Operating Leases Future Minimum Payments and Other Commitments (Details) $ in Millions	Dec. 31, 2015 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Noncancellable operating leases due in 2016	$ 14
Noncancellable operating leases due in 2017	5
Noncancellable operating leases due in 2018	3
Noncancellable operating leases due in 2019	1
Noncancellable operating leases due in 2020	0
Noncancellable operating leases due after 2020	0
Total	23
Other Commitments [Abstract]
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
Other purchase obligations and commitments due in 2020	0
Total	$ 1

Commitments and Contingencies - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) ft² MMcf bbl agreement	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Long-term Purchase Commitment [Line Items]
Rent expense \| $	$ 32	$ 23	$ 12
Area of leased office space (square feet) \| 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	94
Number of compression service agreements on a month-to-month basis	49
Number of compression service agreements expiring in 2016	22
Number of compression service agreements expiring in 2017	19
Number of compression service agreements expiring in 2018	4
Number of gas treating agreements	5
Firm capacity agreement
Long-term Purchase Commitment [Line Items]
Capacity per agreement (barrels per day/ MMcf/d) \| MMcf	275
Duration of firm capacity agreement	10 years
XTO \| Dunn and McKenzie Counties, North Dakota
Long-term Purchase Commitment [Line Items]
Capacity per agreement (barrels per day/ MMcf/d) \| bbl	49,500
Pipeline construction, expected cost remaining \| $	$ 37

Income Taxes - Schedule of Expense (Benefit) (Details) - USD ($) $ in Millions		12 Months Ended
	May 01, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Provision for current income taxes
Federal		$ 0	$ 0	$ 1
State		1	1	1
Total provision for current income taxes		1	1	2
Provision (benefit) for deferred income taxes, net
Federal		0	0	(1,039)
State		(1)	1	(155)
Total provision (benefit) for deferred income taxes, net		(1)	1	(1,194)
Total income tax expense (benefit)	$ 1,240	$ 0	$ 2	(1,192)
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, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Income before income taxes		$ (771)	$ 535	$ 426
Federal statutory rate		0.00%	0.00%	35.00%
Expected federal income tax expense		$ 0	$ 0	$ 149
State income taxes, net of federal income tax		0	2	8
Income not subject to tax		0	0	(103)
Conversion to partnership		0	0	(1,240)
Other, net		0	0	(6)
Total		0	2	(1,341)
Total income tax expense (benefit)	$ 1,240	$ 0	$ 2	$ (1,192)
Effective tax rate		0.00%	0.40%	(275.90%)

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Deferred tax assets	$ 0	$ 0
Deferred tax liabilities:
Depreciation	9	9
Other	(1)	0
Total non-current deferred tax liabilities	8	9
Total non-current deferred tax liabilities	$ 8	$ 9

Equity Based Compensation - Narrative (Details) - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

$ 11

$ 15

$ 0

Performance units

$ 3

501,474

^[1]

563,963

Duration of daily stock price observations to determine expected price volatility

3 years

Award cycle

3 years

1 year

Average volatility period of peer group companies

2 years

Expected price volatility

$ 16.59

^[1]

$ 26.12

27.60%

22.20%

Risk-free interest rate

0.99%

0.83%

Expected life of units (in years)

3 years

Restricted units

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

$ 7

$ 10

^[1]

279,677

Restricted units | Chief Financial Officer

^[1]

$ 17.14

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

4 years

Phantom units

$ 1

$ 2

$ 0

^[1]

9,817

Phantom units | Independent Directors Of Enable GP

^[1]

$ 12.70

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

6,718

Expected life of units (in years)

1 year

1 year

Other Awards

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

^[1]

17,384

Other Awards | Independent Directors Of Enable GP

^[1]

$ 11.12

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

17,384

Common Units | Long Term Incentive Plan

$ 11.12

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

[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.

Equity Based Compensation - Restricted Units (Details) - Restricted units - $ / shares

12 Months Ended

Apr. 16, 2014

Dec. 31, 2015

Dec. 31, 2014

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

^[1]

279,677

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

^[1]

$ 17.14

Chief Executive Officer

Percentage forfeited upon departure

50.00%

Chief Executive Officer | Percentage Based Vesting

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Chief Executive Officer | Vesting on July 15, 2015

375,000

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Chief Executive Officer | Vesting on February 1, 2015

40.00%

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Chief Executive Officer | Vesting on May 29, 2015

20.00%

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Chief Executive Officer | Equal Annual Based Vesting

50.00%

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

150,000

Executive Officer

687,500

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

$ 0.00

$ 22.60

Chief Financial Officer

Chief Financial Officer | Percentage Based Vesting

4 years

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Chief Financial Officer | Equal Annual Based Vesting

137,500

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Chief Financial Officer | Vesting on March 1, 2015

25,000

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Chief Financial Officer | Vesting on March 1, 2016

45.46%

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Certain Partnership Employees

54.54%

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

4 years

Minimum | Certain Partnership Employees

279,677

304,901

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Maximum | Certain Partnership Employees

$ 16.75

$ 23.56

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

$ 19.18

$ 25.50

[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.

Equity Based Compensation - Phantom Units and Other Awards (Details) - $ / shares

12 Months Ended

Apr. 21, 2014

Dec. 31, 2015

Dec. 31, 2014

Phantom units

^[1]

9,817

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

^[1]

$ 12.70

Other Awards

^[1]

17,384

Certain Partnership Employees and Independent Directors of Enable GP | Phantom units

^[1]

$ 11.12

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

9,817

106,718

Certain Partnership Employees | Phantom units

$ 12.70

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Independent Directors Of Enable GP | Phantom units

100,000

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Independent Directors Of Enable GP | Other Awards

6,718

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

17,384

Minimum | Certain Partnership Employees and Independent Directors of Enable GP | Phantom units

$ 11.12

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Maximum | Certain Partnership Employees and Independent Directors of Enable GP | Phantom units

$ 23.16

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Weighted Average Grant-Date Fair Value, Per Unit

$ 23.70

[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.

Equity Based Compensation - Equity Units Activity (Details) - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Minimum

Performance target percentage

0.00%

Maximum

Weighted Average Grant-Date Fair Value, Per Unit

Performance target percentage

200.00%

Performance units

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

552,581

501,474

^[1]

563,963

(1,254)

(238,291)

Weighted Average Grant-Date Fair Value, Per Unit

814,510

552,581

$ 26.12

16.59

^[1]

$ 26.12

26.12

24.70

Aggregate Intrinsic Value of Units Outstanding at 12/31/2015

$ 20.67

$ 26.12

$ 6

Aggregate Intrinsic Value of Units Vested

Fair Value of Units Vested

$ 0

Restricted units

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

838,068

^[1]

279,677

(400,801)

(135,172)

Weighted Average Grant-Date Fair Value, Per Unit

581,772

838,068

$ 23.47

^[1]

17.14

22.72

23.06

Aggregate Intrinsic Value of Units Outstanding at 12/31/2015

$ 21.04

$ 23.47

$ 5

Aggregate Intrinsic Value of Units Vested

Fair Value of Units Vested

$ 13

Phantom units

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

98,718

^[1]

9,817

(96,718)

(2,000)

Weighted Average Grant-Date Fair Value, Per Unit

9,817

98,718

$ 23.20

^[1]

12.70

23.20

23.16

Aggregate Intrinsic Value of Units Outstanding at 12/31/2015

$ 12.70

$ 23.20

$ 0

Aggregate Intrinsic Value of Units Vested

Fair Value of Units Vested

$ 2

Other Awards

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

^[1]

17,384

(17,384)

Weighted Average Grant-Date Fair Value, Per Unit

$ 0.00

^[1]

11.12

11.12

0.00

Aggregate Intrinsic Value of Units Outstanding at 12/31/2015

$ 0.00

$ 0

[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.

Equity Based Compensation - Unrecognized Compensation Cost (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 19
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 26 days
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 8
Weighted Average to be Recognized (In years)	1 year 8 months 27 days
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 0
Weighted Average to be Recognized (In years)	4 months 6 days
Long Term Incentive Plan \| Common Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for issuance \| shares	11,054,681

- Schedule of Financial Data for Business Segments and Services (Details)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2015

USD ($)

Sep. 30, 2015

USD ($)

Jun. 30, 2015

USD ($)

Mar. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Sep. 30, 2014

USD ($)

Jun. 30, 2014

USD ($)

Mar. 31, 2014

USD ($)

Dec. 31, 2015

USD ($)

segment

Dec. 31, 2014

USD ($)

Dec. 31, 2013

USD ($)

Number of reportable segments | segment

Cost of goods sold, excluding depreciation and amortization

$ 566

$ 646

$ 590

$ 616

$ 735

$ 803

$ 827

$ 1,002

$ 2,418

^[1]

$ 3,367

^[1]

$ 2,489

^[1]

241

287

277

292

364

439

478

633

1,097

1,914

1,313

Operation and maintenance, General and administrative

522

527

429

318

276

212

1,134

^[2]

$ (975)

^[2]

$ 93

^[2]

$ 104

^[2]

134

$ 152

$ 138

$ 162

(712)

586

469

11,238

11,837

11,238

11,837

11,232

949

869

837

573

Gathering and Processing

Cost of goods sold, excluding depreciation and amortization

^[1]

1,663

2,424

1,740

908

1,585

1,075

Operation and maintenance, General and administrative

293

297

222

195

160

117

543

(306)

349

294

7,548

8,356

7,548

8,356

7,157

839

Transportation and Storage

740

431

Cost of goods sold, excluding depreciation and amortization

^[1],[3]

1,132

1,577

1,149

^[3]

565

961

636

Operation and maintenance, General and administrative

^[3]

230

232

209

^[3]

123

116

^[3]

591

^[3]

^[3]

(406)

237

175

^[3]

4,976

5,493

4,976

5,493

5,717

^[3]

110

^[3]

103

142

Eliminations

Cost of goods sold, excluding depreciation and amortization

^[1]

(377)

(634)

(400)

(376)

(632)

(398)

Operation and maintenance, General and administrative

(1)

(2)

$ (1,286)

$ (2,012)

(1,286)

(2,012)

(1,642)

$ 0

Revenues (including revenues from affiliates (Note 13))

$ (6)

$ 0

[1]	The Partnership had no external customers accounting for 10% or more of revenues in periods shown. See Note 14 for revenues from affiliated companies.
[2]	In the third quarter of 2015, the Partnership recorded a $1,087 million impairment to goodwill. For more information see Note 8.
[3]	See Note 9 for discussion regarding ownership interest in SESH and related equity earnings included in the Transportation and Storage segment for the years ended December 31, 2015, 2014 and 2013.

Quarterly Financial Data (Unaudited) - Narrative (Details) - USD ($)

3 Months Ended

4 Months Ended

8 Months Ended

12 Months Ended

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Apr. 30, 2013

Dec. 31, 2013

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

$ 566,000,000

$ 646,000,000

$ 590,000,000

$ 616,000,000

$ 735,000,000

$ 803,000,000

$ 827,000,000

$ 1,002,000,000

$ 2,418,000,000

^[1]

$ 3,367,000,000

^[1]

$ 2,489,000,000

^[1]

Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)

241,000,000

287,000,000

277,000,000

292,000,000

364,000,000

439,000,000

478,000,000

633,000,000

1,097,000,000

1,914,000,000

1,313,000,000

66,000,000

^[2]

(975,000,000)

^[2]

93,000,000

^[2]

104,000,000

^[2]

134,000,000

152,000,000

138,000,000

162,000,000

(712,000,000)

586,000,000

469,000,000