View Filing Data

$ 1,172

$ 1,334

$ 2,300

1,100

1,084

1,067

Cost and Expenses (including expenses from affiliates (Note 14)):

^[1]

2,272

2,418

3,367

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

1,017

1,097

1,914

Operation and maintenance

367

419

420

General and administrative

103

107

338

318

276

1,134

Total Cost and Expenses

1,887

3,130

2,781

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

385

(712)

586

Other Income (Expense):

(99)

(90)

(70)

Total Other Income (Expense)

Other, net

(1)

(71)

(59)

(51)

Income (Loss) Before Income Taxes

Income (Loss) Before Income Taxes

314

(771)

535

Income tax expense

Net Income (Loss)

Net Income (Loss)

313

(771)

533

Less: Net income (loss) attributable to noncontrolling interest

Less: Net income (loss) attributable to noncontrolling interest

(19)

Net Income (Loss) Attributable to Limited Partners

Net Income (Loss) Attributable to Limited Partners

312

(752)

530

Less: Series A Preferred Unit distributions (Note 5)

Less: Series A Preferred Unit distributions (Note 5)

Net Income (Loss) Attributable to Common and Subordinated Units (Note 4)

Net Income (Loss) Attributable to Common and Subordinated Units (Note 4)

290

(752)

530

Common Units

Net Income (Loss) Attributable to Common and Subordinated Units (Note 4)

Net Income (Loss) Attributable to Common and Subordinated Units (Note 4)

$ 148

$ (381)

$ 339

Basic and Diluted earnings (loss) per unit

Basic earnings (loss) per unit (Note 4)

$ 0.69

$ (1.78)

$ 1.29

Diluted earnings (loss) per unit (Note 4)

$ 0.69

$ (1.78)

$ 1.29

Subordinated Units

Net Income (Loss) Attributable to Common and Subordinated Units (Note 4)

Net Income (Loss) Attributable to Common and Subordinated Units (Note 4)

$ 142

$ (371)

$ 191

Basic and Diluted earnings (loss) per unit

Basic earnings (loss) per unit (Note 4)

$ 0.68

$ (1.78)

$ 1.28

Diluted earnings (loss) per unit (Note 4)

$ 0.68

$ (1.78)

$ 1.28

[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.

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 313	$ (771)	$ 533
Comprehensive Income (Loss)	313	(771)	533
Less: Comprehensive income (loss) attributable to noncontrolling interest	1	(19)	3
Comprehensive Income (Loss) Attributable to Enable Midstream Partners, LP	$ 312	$ (752)	$ 530

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current Assets:
Cash and cash equivalents	$ 6	$ 4
Restricted cash	17	0
Accounts receivable, net	249	245
Accounts receivable—affiliated companies	13	21
Inventory	41	53
Gas imbalances	41	23
Other current assets	29	35
Total current assets	396	381
Property, Plant and Equipment:
Property, plant and equipment	11,567	11,293
Less accumulated depreciation and amortization	1,424	1,162
Property, plant and equipment, net	10,143	10,131
Other Assets:
Intangible assets, net	306	333
Investment in equity method affiliate	329	344
Other	38	37
Total other assets	673	714
Total Assets	11,212	11,226
Current Liabilities:
Accounts payable	181	248
Accounts payable—affiliated companies	3	9
Short-term debt	0	236
Taxes accrued	30	30
Gas imbalances	35	25
Accrued compensation	37	23
Customer deposits	31	18
Other	45	26
Total current liabilities	362	615
Other Liabilities:
Accumulated deferred income taxes, net	10	8
Notes payable—affiliated companies	0	363
Regulatory liabilities	19	18
Other	34	20
Total other liabilities	63	409
Long-Term Debt	2,993	2,671
Commitments and Contingencies (Note 15)
Partners’ Equity:
Common units (224,535,454 issued and outstanding at December 31, 2016 and 214,541,422 issued and outstanding at December 31, 2015, respectively)	3,737	3,714
Subordinated units (207,855,430 issued and outstanding at December 31, 2016 and December 31, 2015, respectively)	3,683	3,805
Noncontrolling interest	12	12
Total Partners’ Equity	7,794	7,531
Total Liabilities and Partners’ Equity	11,212	11,226
Series A Preferred Units
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at December 31, 2016 and 0 issued and outstanding at December 31, 2015)	$ 362	$ 0

Consolidated Balance Sheets - Parenthetical - shares	Dec. 31, 2016	Dec. 31, 2015
Common units issued	224,535,454	214,541,422
Common units outstanding	224,535,454	214,541,422
Subordinated units issued	207,855,430	207,855,430
Subordinated units outstanding	207,855,430	207,855,430
Series A Preferred Units
Preferred units issued	14,520,000	0
Preferred units outstanding	14,520,000	0

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Cash Flows [Abstract]
Net income (loss)	$ 313	$ (771)	$ 533
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	338	318	276
Deferred income taxes	2	(1)	1
Impairments	9	1,134	8
Loss on sale/retirement of assets	17	5	0
Equity in earnings of equity method affiliate, net of distributions	0	5	3
Equity based compensation	13	9	13
Amortization of debt expense and discount (premium)	(3)	(2)	(1)
Changes in other assets and liabilities:
Accounts receivable, net	(4)	9	52
Accounts receivable—affiliated companies	8	6	1
Inventory	12	10	7
Gas imbalance assets	(18)	22	(35)
Other current assets	6	2	17
Other assets	(1)	(4)	5
Accounts payable	(34)	0	(138)
Accounts payable—affiliated companies	(6)	(29)	(2)
Gas imbalance liabilities	10	12	0
Other current liabilities	45	6	29
Other liabilities	14	(5)	0
Net cash provided by operating activities	721	726	769
Cash Flows from Investing Activities:
Capital expenditures	(383)	(869)	(837)
Acquisitions, net of cash acquired	0	(80)	0
Proceeds from sale of assets	1	3	13
Return of investment in equity method affiliate	15	8	198
Investment in equity method affiliate	0	(8)	(189)
Net cash used in investing activities	(367)	(946)	(815)
Cash Flows from Financing Activities:
Repayment of long term debt	0	0	(1,500)
Proceeds from long term debt, net of issuance costs	0	450	1,635
Proceeds from revolving credit facility	1,734	585	122
Repayment of revolving credit facility	(1,408)	(275)	(495)
Increase (decrease) in short-term debt	(236)	(17)	253
Repayment of notes payable—affiliated companies	(363)	0	0
Proceeds from issuance of common units	137	0	464
Proceeds from issuance of Series A Preferred Units, net of issuance costs	362	0	0
Distributions	(561)	(531)	(529)
Net cash provided by (used in) financing activities	(335)	212	(50)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	19	(8)	(96)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	4	12	108
Cash, Cash Equivalents and Restricted Cash at End of Period	$ 23	$ 4	$ 12

Consolidated Statements of Partners' Equity - USD ($) shares in Millions, $ in Millions	Total	Partners' Capital	Noncontrolling Interest	Series A Preferred Units Preferred Units	Common Units Partners' Capital	Subordinated Units Partners' Capital
Balance, beginning of period (in units) at Dec. 31, 2013				0	390	0
Balance, beginning of period at Dec. 31, 2013	$ 8,181		$ 33	$ 0	$ 8,148	$ 0
Changes in Partners' Capital
Conversion to subordinated units (in units)					(208)	208
Conversion to subordinated units	0				$ (4,372)	$ 4,372
Net income (loss)	533		3		$ 349	181
Issuance of IPO common units (in units)					25
Issuance of IPO common units	464				$ 464
Issuance of units upon acquisition (in units)					6
Issuance of units upon acquisition	161				$ 161
Distributions	(529)		(5)		$ (410)	$ (114)
Equity based compensation (in units)					1
Equity based compensation, net of units for employee taxes	13				$ 13
Balance, end of period (in units) at Dec. 31, 2014				0	214	208
Balance, end of period at Dec. 31, 2014	8,823		31	$ 0	$ 4,353	$ 4,439
Changes in Partners' Capital
Net income (loss)	(771)		(19)		(379)	(373)
Issuance of units upon acquisition	1	$ 1
Distributions	(531)				(270)	$ (261)
Equity based compensation, net of units for employee taxes	9				$ 9
Balance, end of period (in units) at Dec. 31, 2015				0	214	208
Balance, end of period at Dec. 31, 2015	7,531		12	$ 0	$ 3,714	$ 3,805
Changes in Partners' Capital
Net income (loss)	313		1	$ 22	$ 147	143
Issuance of Series A Preferred Units (in units)				15
Issuance of Series A Preferred Units	362			$ 362
Issuance of common units (in units)					10
Issuance of common units	137				$ 137
Distributions	(562)		(1)	$ (22)	(274)	$ (265)
Equity based compensation, net of units for employee taxes	13				$ 13
Balance, end of period (in units) at Dec. 31, 2016				15	224	208
Balance, end of period at Dec. 31, 2016	$ 7,794		$ 12	$ 362	$ 3,737	$ 3,683

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

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, OGE Energy and ArcLight, pursuant to the terms of the MFA. The Partnership’s assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. The gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers. The transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers. The Partnership’s natural gas gathering and processing assets are primarily located in Oklahoma, Texas, Arkansas and Louisiana and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Crude oil gathering assets are located in North Dakota and serve crude oil production in the Bakken Shale formation of the Williston Basin. The Partnership’s natural gas transportation and storage assets consist primarily of an interstate pipeline system extending from western Oklahoma and the Texas Panhandle to Louisiana, an interstate pipeline system extending from Louisiana to Illinois, an intrastate pipeline system in Oklahoma, and our investment in SESH, a pipeline extending from Louisiana to Alabama.

CenterPoint Energy and OGE Energy each have 50% of the management interests in Enable GP. Enable GP is the general partner of the Partnership and has no other operating activities. Enable GP is governed by a board made up of two representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership’s Chief Executive Officer and three independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. 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, 2016, CenterPoint Energy held approximately 54.1% of the Partnership’s common and subordinated units, or 94,151,707 common units and 139,704,916 subordinated units, and OGE Energy held approximately 25.7% of the Partnership’s common and subordinated units, or 42,832,291 common units and 68,150,514 subordinated units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred 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.

For the period from December 31, 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. As of December 31, 2016, the Partnership owned a 50% interest in SESH. See Note 9 for further discussion of SESH.

In addition, for the years ended December 31, 2016, 2015 and 2014, the Partnership held a 50% ownership interest in Atoka and consolidated Atoka in its 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 IPO of 25,000,000 common units 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 IPO, 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 IPO 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 IPO, 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 consolidated financial statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP.

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 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, net or Accounts receivable—affiliated companies, as appropriate, on the Consolidated Balance Sheets and in Revenues on the 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 had $34 million and $30 million of deferred revenues, including deferred revenue—affiliated companies, on the Consolidated Balance Sheets at December 31, 2016 and 2015, 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, 2016, 2015 and 2014, one third party purchased approximately 22%, 18% and 21%, respectively, of the NGLs delivered off our system, which accounted for approximately $129 million, $108 million and $235 million, or 6%, 4% and 7%, respectively, of total revenues. Other than revenues from affiliates discussed in Note 14, there are no other revenue concentrations with individual customers in the years ended December 31, 2016, 2015 and 2014.

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 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, 2016 or 2015.

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

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

We account for deferred income taxes related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future taxes attributable to the difference between financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of tax net operating loss carryforwards. In the event future utilization is determined to be unlikely, a valuation allowance is provided to reduce the tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the period in which the temporary differences and carryforwards are expected to be recovered or settled. The effect of a change in tax rates is recognized in the period which includes the enactment date. The Partnership recognizes interest and penalties as a component of income tax expense.

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 $6 million and $4 million of cash and cash equivalents as of December 31, 2016 and 2015, respectively.

Restricted Cash

Restricted cash consists of cash which is restricted by agreements with third parties. The Consolidated Balance Sheets have $17 million of restricted cash as of December 31, 2016. The Partnership had no restricted cash as of December 31, 2015.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are recorded at the invoiced amount and do not typically bear interest. The determination of the allowance for doubtful accounts requires management to make estimates and judgments regarding our customers’ ability to pay. The allowance for doubtful accounts is determined based upon specific identification and estimates of future uncollectable amounts. On an ongoing basis, we evaluate our customers’ financial strength based on aging of accounts receivable, payment history and review of other relevant information, including ratings agency credit ratings and alerts, publicly available reports and news releases, and bank and trade references. It is the policy of management to review the outstanding accounts receivable at least quarterly, giving consideration to historical bad debt write-offs, the aging of receivables and specific customer circumstances that may impact their ability to pay the amounts due. Based on this review, management determined that a $3 million allowance for doubtful accounts was required as of December 31, 2016, and no allowance for doubtful accounts was required as of December 31, 2015.

Inventory

Materials and supplies inventory is valued at cost and is subsequently recorded at the lower of cost or net realizable value. During the years ended December 31, 2016 and 2014, the Partnership recorded write-downs to net realizable value related to materials and supplies inventory disposed or identified as excess or obsolete of $1 million and $9 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 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 net realizable value. During the years ended December 31, 2016, 2015 and 2014, the Partnership recorded write-downs to net realizable value related to natural gas and natural gas liquids inventory of $3 million, $13 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 Consolidated Statements of Income.



	December 31,
	2016		2015
	(In millions)
Materials and supplies	$	30	$	34
Natural gas and natural gas liquids inventories	11		19
Total	$	41	$	53

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 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, 2016 and 2015, these removal costs of $19 million and $18 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, 2016, 2015 and 2014, the Partnership capitalized interest and AFUDC of $4 million, $10 million and $8 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. For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized in Product sales in the Consolidated Statements of Income. 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 performance units, time-based phantom units (phantom units) and time-based restricted units (restricted units) are recognized in the 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 consolidated financial statements reflect the effects of the reverse unit split.

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

On February 18, 2016, in connection with the closing of the private placement of 14,520,000 Series A Preferred Units and pursuant to the Purchase Agreement, the General Partner adopted the Third Amended and Restated Agreement of Limited Partnership which, among other things, authorized and established the terms of the Series A Preferred Units and the other series of preferred units that are issuable upon conversion of the Series A Preferred Units. For further information related to the issuance of the Series A Preferred Units, see Note 5.

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

On June 22, 2016, the General Partner adopted the Fourth Amended and Restated Agreement of Limited Partnership (the Partnership Agreement), which changed the last permitted distribution date with respect to each fiscal quarter from 45 days following the close of such quarter to 60 days following the close of such quarter.

New Accounting Pronouncements	12 Months Ended
New Accounting Pronouncements	Dec. 31, 2016
Accounting Changes and Error Corrections [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements Revenue from Contracts with Customers In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which supersedes the revenue recognition requirements in “Revenue Recognition (Topic 605).” Topic 606 is based on the core principle that revenue is recognized to depict 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. Topic 606 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. Topic 606 is effective for fiscal years beginning after December 15, 2017, and interim periods within those years, with early adoption permitted in 2017, however we do not plan to adopt the standard early. Entities will have the option to apply the standard using a full retrospective or modified retrospective adoption method. The Partnership expects to adopt this ASU using the modified retrospective method. Our evaluation of the impact on our Consolidated Financial Statements and related disclosures is ongoing and not complete. In connection with our assessment work, we formed an implementation work team, completed training on the Topic 606 revenue recognition model and are continuing our review of contracts relative to the provisions of Topic 606. Leases In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” This standard requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Partnership expects to adopt this standard in the first quarter of 2019 and is currently evaluating the impact of this standard on our Consolidated Financial Statements and related disclosures. In connection with our assessment work, we formed an implementation work team and are continuing a review of our contracts relative to the provisions of the lease standard. Share-Based Compensation In March 2016, the FASB issued ASU No. 2016-09, “Compensation—Stock Compensation (Topic 718).” This standard makes several modifications to Topic 718 related to the accounting for forfeitures, employer tax withholding on share-based compensation and the financial statement presentation of excess tax benefits or deficiencies. ASU 2016-09 also clarifies the statement of cash flows presentation for certain components of share-based awards. The standard is effective for interim and annual reporting periods beginning in 2017, although early adoption is permitted. The Partnership will adopt the amendment in the fourth quarter of 2017, and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures. Financial Instruments—Credit Losses In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This standard requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions and reasonable and supportable forecasts in order to record credit losses in a more timely matter. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. The guidance requires application using a modified retrospective method. The Partnership does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures. Statement of Cash Flows In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” This standard is intended to reduce existing diversity in practice in how certain transactions are presented on the statement of cash flows. The standard is effective for interim and annual reporting periods beginning after December 15, 2017, although early adoption is permitted. The guidance requires application using a retrospective transition method. The Partnership will adopt ASU No. 2016-15 in the first quarter of 2017 and has determined the amendment will not have a material impact on our Consolidated Financial Statements and related disclosures. Income Taxes In October 2016, the FASB issued ASU No. 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory.” This standard requires entities to recognize the tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The standard is effective for interim and annual reporting periods beginning after December 15, 2017, although early adoption is permitted as of the beginning of an annual period (i.e., only in the first interim period). The guidance requires application using a modified retrospective approach. The Partnership is currently evaluating the impact, if any, the adoption of this standard will have on our Consolidated Financial Statements and related disclosures. Restricted Cash In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash.” The standard is intended to provide specific guidance on the cash flow classification and presentation of changes in restricted cash. The Partnership early adopted the amendment in the fourth quarter of 2016, using a retrospective basis. As of December 31, 2016, the Partnership had restricted cash of $17 million. The Partnership had no restricted cash as of December 31, 2015.

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
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-URI http://asc.fasb.org/extlink&oid=6507316

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Acquisition

12 Months Ended

Dec. 31, 2016

Business Combinations [Abstract]

Acquisition

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 Consolidated Statements of Income.

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).

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Earnings Per Limited Partner Unit

Earnings Per Limited Partner Unit

12 Months Ended

Dec. 31, 2016

Earnings Per Share [Abstract]

Basic and diluted earnings per limited partner unit is calculated by dividing net income (loss) allocable to common and subordinated unitholders by the weighted average number of common and subordinated 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, 2016, 2015 and 2014.

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



	Year Ended December 31,
	2016		2015			2014
	(In millions, except per unit data)
Net income (loss)	$	313	$	(771	)	$	533
Net income (loss) attributable to noncontrolling interest	1		(19		)	3
Series A Preferred Unit distribution	22		—			—
General partner interest in net income	—		—			—
Net income (loss) available to common and subordinated unitholders	$	290	$	(752	)	$	530

Net income (loss) allocable to common units	$	148	$	(381	)	$	339
Net income (loss) allocable to subordinated units	142		(371		)	191
Net income (loss) available to common and subordinated unitholders	$	290	$	(752	)	$	530

Net income (loss) allocable to common units	$	148	$	(381	)	$	339
Dilutive effect of Series A Preferred Unit distribution	—		—			—
Dilutive effect of performance units	—		—			—
Diluted net income (loss) allocable to common units	148		(381		)	339
Diluted net income (loss) allocable to subordinated units	142		(371		)	191
Total	$	290	$	(752	)	$	530

Basic weighted average number of outstanding
Common units	216		214			264
Subordinated units	208		208			148
Total	424		422			412

Basic earnings (loss) per unit
Common units	$	0.69	$	(1.78	)	$	1.29
Subordinated units	$	0.68	$	(1.78	)	$	1.28

Basic weighted average number of outstanding common units	216		214			264
Dilutive effect of Series A Preferred Units	—		—			—
Dilutive effect of performance units	—		—			—
Diluted weighted average number of outstanding common units	216		214			264
Diluted weighted average number of outstanding subordinated units	208		208			148
Total	424		422			412

Diluted earnings (loss) per unit
Common units	$	0.69	$	(1.78	)	$	1.29
Subordinated units	$	0.68	$	(1.78	)	$	1.28

Enable Midstream Partners, LP Partners' Equity

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

Enable Midstream Partners, LP Partners' Equity

Enable Midstream Partners, LP Partners’ Equity

The Partnership Agreement requires that, within 60 days subsequent to the end of each quarter, the Partnership distribute all of its available cash (as defined in the Partnership Agreement) 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 IPO, other than the required distributions to CenterPoint Energy, OGE Energy and ArcLight under the Partnership Agreement.

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 paid or has authorized payment of the following cash distributions to common and subordinated unitholders during 2016, 2015 and 2014 (in millions, except for per unit amounts):



Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
December 31, 2016⁽¹⁾	February 21, 2017	February 28, 2017	$	0.318	$	137
September 30, 2016	November 14, 2016	November 22, 2016	$	0.318	$	134
June 30, 2016	August 16, 2016	August 23, 2016	$	0.318	$	134
March 31, 2016	May 6, 2016	May 13, 2016	$	0.318	$	134
December 31, 2015	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 February 10, 2017, to be paid on February 28, 2017, to common and subordinated unitholders of record at the close of business on February 21, 2017.


(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 IPO, April 16, 2014 through June 30, 2014.

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2016 (in millions, except for per unit amounts):



Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
December 31, 2016⁽¹⁾	February 10, 2017	February 15, 2017	$	0.625	$	9
September 30, 2016	November 1, 2016	November 14, 2016	$	0.625	$	9
June 30, 2016	August 2, 2016	August 12, 2016	$	0.625	$	9
March 31, 2016⁽²⁾	May 6, 2016	May 13, 2016	$	0.2917	$	4

_____________________


(1)	The board of directors of Enable GP declared this $0.625 per Series A Preferred Unit cash distribution on February 10, 2017, which was paid on February 15, 2017 to Series A Preferred unitholders of record at the close of business on February 10, 2017.


(2)	The prorated quarterly distribution for the Series A Preferred Units is for a partial period beginning on February 18, 2016, and ending on March 31, 2016, which equates to $0.625 per unit on a full-quarter basis or $2.50 per unit on an annualized basis.

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 (as defined in the Partnership Agreement) 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

General

As of December 31, 2016, all subordinated units are held by CenterPoint Energy and OGE Energy. These units are considered subordinated because for a period of time, defined by the Partnership Agreement as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received distributions of available cash each quarter from operating surplus in an amount equal to the minimum quarterly distribution plus any arrearages on minimum quarterly distributions on the common units from prior quarters. In addition, the subordinated units are not entitled to arrearages on minimum quarterly distributions. On the expiration of the subordination period, the subordinated units will convert to common units on a one-for-one basis.

Subordination Period

The subordination period began on the closing date of the IPO and expires on the first to occur of the following dates: (1) the first business day following the distribution of available cash in respect of any quarter beginning with the quarter ending June 30, 2017 that the following tests are met: (a) distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equal or exceed $1.15 per unit (the annualized minimum quarterly distribution) for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date; (b) the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum $1.15 (the annualized minimum quarterly distribution) on all of the common units and subordinated units outstanding during those periods on a fully diluted weighted average basis; and (c) there are no arrearages in the payment of the minimum quarterly distributions on the common units or (2) the first business day following the distribution of available cash in respect of any quarter beginning with the quarter ending June 30, 2015 that the following tests are met: (a) 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% of the annualized minimum quarterly distribution) for the four consecutive quarter period immediately preceding that date; (b) the adjusted operating surplus generated during the four consecutive quarter period immediately preceding that date equaled or exceed $1.725 per unit (150% of the annualized minimum quarterly distribution) on all of the common units and subordinated units outstanding during that period on a fully diluted weighted average basis plus the corresponding incentive distribution rights; and (c) there are no arrearages in the payment of the minimum quarterly distributions on the common units.

Series A Preferred Units

On February 18, 2016, the Partnership completed the private placement of 14,520,000 Series A Preferred Units representing limited partner interests in the Partnership for a cash purchase price of $25.00 per Series A Preferred Unit, resulting in proceeds of $362 million, net of issuance costs. The Partnership incurred approximately $1 million of expenses related to the offering, which is shown as an offset to the proceeds. In connection with the closing of the private placement, the Partnership redeemed approximately $363 million of notes scheduled to mature in 2017 payable to a wholly-owned subsidiary of CenterPoint Energy.

Pursuant to the Partnership Agreement, the Series A Preferred Units:


•	rank senior to the Partnership’s common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up;


•	have no stated maturity;


•	are not subject to any sinking fund; and


•	will remain outstanding indefinitely unless repurchased or redeemed by the Partnership or converted into its common units in connection with a change of control.

Holders of the Series A Preferred Units receive a quarterly cash distribution on a non-cumulative basis if and when declared by the General Partner, and subject to certain adjustments, equal to an annual rate of: 10% on the stated liquidation preference of $25.00 from the date of original issue to, but not including, the five year anniversary of the original issue date; and thereafter a percentage of the stated liquidation preference equal to the sum of the three-month LIBOR plus 8.5%.

At any time on or after five years after the original issue date, the Partnership may redeem the Series A Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.50 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, the Partnership (or a third-party with its prior written consent) may redeem the Series A Preferred Units following certain changes in the methodology employed by ratings agencies, changes of control or fundamental transactions as set forth in the Partnership Agreement. If, upon a change of control or certain fundamental transactions, the Partnership (or a third-party with its prior written consent) does not exercise this option, then the holders of the Series A Preferred Units have the option to convert the Series A Preferred Units into a number of common units per Series A Preferred Unit as set forth in the Partnership Agreement. The Series A Preferred Units are also required to be redeemed in certain circumstances if they are not eligible for trading on the New York Stock Exchange.

Holders of Series A Preferred Units have no voting rights except for limited voting rights with respect to potential amendments to the Partnership Agreement that have a material adverse effect on the existing terms of the Series A Preferred Units, the issuance by the Partnership of certain securities, approval of certain fundamental transactions and as required by law.

Upon the transfer of any Series A Preferred Unit to a non-affiliate of CenterPoint Energy, the Series A Preferred Units will automatically convert into a new series of preferred units (the Series B Preferred Units) on the later of the date of transfer and the second anniversary of the date of issue. The Series B Preferred Units will have the same terms as the Series A Preferred Units except that unpaid distributions on the Series B Preferred Units will accrue on a cumulative basis until paid.

On February 18, 2016, the Partnership entered into a registration rights agreement with CenterPoint Energy, pursuant to which, among other things, the Partnership gave CenterPoint Energy certain rights to require the Partnership to file and maintain a registration statement with respect to the resale of the Series A Preferred Units and any other series of preferred units or common units representing limited partner interests in the Partnership that are issuable upon conversion of the Series A Preferred Units.

2016 Equity Issuance

On November 29, 2016, the Partnership closed a public offering of 10,000,000 common units at a price to the public of $14.00 per common unit. In connection with the offering, the Partnership, the underwriters and an affiliate of ArcLight entered into an underwriting agreement that provided an option for the underwriters to purchase up to an additional 1,500,000 common units, with 75,719 common units to be sold by the Partnership and 1,424,281 to be sold by the affiliate of ArcLight. The underwriters exercised the option to purchase all of the additional common units, and the Partnership received proceeds (net of underwriting discounts, structuring fees and offering expenses) of $137 million from the offering.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2016

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)	2016		2015
		(In millions)
Property, plant and equipment, gross:
Gathering and Processing	37	$	6,987	$	6,478
Transportation and Storage	36	4,498		4,444
Construction work-in-progress		82		371
Total		$	11,567	$	11,293
Accumulated depreciation:
Gathering and Processing		681		510
Transportation and Storage		743		652
Total accumulated depreciation		1,424		1,162
Property, plant and equipment, net		$	10,143	$	10,131

The Partnership recorded depreciation expense of $311 million, $291 million and $249 million during the years ended December 31, 2016, 2015 and 2014, respectively.

Intangible Assets, Net

12 Months Ended

Dec. 31, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets, Net

As of December 31, 2016, the Partnership has $405 million 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,
	2016		2015
	(In millions)
Customer relationships:
Total intangible assets	$	405	$	405
Accumulated amortization	99		72
Net intangible assets	$	306	$	333

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 $27 million during the years ended December 31, 2016, 2015 and 2014, respectively. The following table summarizes the Partnership’s expected amortization of intangible assets for each of the next five years:



	2017		2018		2019		2020		2021
	(In millions)
Expected amortization of intangible assets	$	27	$	27	$	27	$	27	$	27

Goodwill

12 Months Ended

Dec. 31, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill

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 was related to the original acquisitions of EGT and MRT in 1997 by predecessors of the Partnership. 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 our annual goodwill impairment analysis as of October 1, 2015, we determined that goodwill was completely impaired in the amount of $1,087 million, which is included in Impairments on the Consolidated Statements of Income for the year ended December 31, 2015. As a result, the Partnership did not have any goodwill recorded as of December 31, 2016 and 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 31, 2014	$	489		$	579		$	1,068
Acquisition of Monarch	19			—			19
Goodwill impairment	(508		)	(579		)	(1,087		)
Balance as of December 31, 2015	$	—		$	—		$	—

Balance as of December 31, 2016	$	—		$	—		$	—

Investment in Equity Method Affiliate

12 Months Ended

Dec. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

Investment in Equity Method Affiliate

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.

For the period December 31, 2013 through May 29, 2014, the Partnership held a 24.95% interest in SESH, which is accounted for as an investment in equity method affiliate, 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, 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, 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, subject to certain exceptions. As of December 31, 2016, 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, 2016, 2015 and 2014, the Partnership billed SESH $13 million, $12 million and $13 million, respectively, associated with these service agreements.

The Partnership includes equity in earnings of equity method affiliate under the Other Income (Expense) caption in the Consolidated Statements of Income for the years ended December 31, 2016, 2015 and 2014.

Investment in Equity Method Affiliate:



	(In millions)
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⁽¹⁾	(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⁽¹⁾	(42		)
Balance as of December 31, 2015	344
Equity in earnings of equity method affiliate	28
Distributions from equity method affiliate⁽¹⁾	(43		)
Balance as of December 31, 2016	$	329

____________________


(1)	Distributions from equity method affiliate includes a $28 million, $34 million and $23 million return on investment and a $15 million, $8 million and zero return of investment for the years ended December 31, 2016, 2015 and 2014, respectively.

Equity in Earnings of Equity Method Affiliate:



	Year Ended December 31,
	2016		2015		2014
	(In millions)
SESH	$	28	$	29	$	20

Distributions from Equity Method Affiliate:



	Year Ended December 31,
	2016		2015		2014
	(In millions)
SESH ⁽¹⁾	$	43	$	42	$	23

_____________________


(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:



	December 31,
	2016			2015
	(In millions)
Balance Sheet Data:
Current assets	$	31		$	45
Property, plant and equipment, net	1,110			1,127
Total assets	$	1,141		$	1,172
Current liabilities	$	18		$	18
Long-term debt	397			397
Members’ equity	726			757
Total liabilities and members’ equity	$	1,141		$	1,172
Reconciliation:
Investment in SESH	$	329		$	344
Less: Capitalized interest on investment in SESH	(1		)	(1		)
Add: Basis differential, net of amortization	35			36
The Partnership’s share of members’ equity	$	363		$	379



	Year Ended December 31,
	2016		2015		2014
	(In millions)
Income Statement Data:
Revenues	$	115	$	115	$	108
Operating income	$	73	$	71	$	69
Net income	$	55	$	57	$	48

Debt

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Debt

The following table presents the Partnership’s outstanding debt as of December 31, 2016 and 2015.



	December 31,
	2016		2015
	(In millions)
Commercial Paper	$	—	$	236
Revolving Credit Facility	636		310
2015 Term Loan Agreement	450		450
Notes payable—affiliated companies (Note 14)	—		363
2019 Notes	500		500
2024 Notes	600		600
2044 Notes	550		550
EOIT Senior Notes	250		250
Premium (Discount) on long-term debt	17		23
Total debt	3,003		3,282
Less: Short-term debt⁽¹⁾	—		236
Less: Unamortized debt expense	10		12
Less: Notes payable—affiliated companies	—		363
Total long-term debt	$	2,993	$	2,671

___________________


(1)	There were no commercial paper borrowings outstanding as of December 31, 2016. Short-term debt includes $236 million of commercial paper as of December 31, 2015.

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



2017	$	—
2018	450
2019	500
2020	886
2021	—
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, 2016, there were $636 million of principal advances and $3 million in letters of credit outstanding under the Revolving Credit Facility. The weighted average interest rate of the Revolving Credit Facility was 2.21% as of December 31, 2016.

The Revolving Credit Facility provides that outstanding borrowings bear interest at 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, 2016, 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, 2016, 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 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 zero and $236 million outstanding under our commercial paper program as of December 31, 2016 and 2015, respectively. On February 2, 2016, Standard & Poor’s Ratings Services lowered its credit rating on the Partnership from an investment grade rating to a non-investment grade rating. The short-term rating on the Partnership was also reduced from an investment grade rating to a non-investment grade rating. As a result of the downgrade, the Partnership repaid its outstanding borrowings under the commercial paper program upon maturity and did not issue any additional commercial paper.

Term Loan Agreement

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 agreement (2015 Term Loan Agreement). The entire $450 million principal amount of the 2015 Term Loan Agreement was borrowed by the Partnership on July 31, 2015. The 2015 Term Loan Agreement contains an option, which may be exercised up to two times, to extend the term of the 2015 Term Loan Agreement, in each case, for an additional one-year term. The 2015 Term Loan Agreement 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, 2016, there was $450 million outstanding under the 2015 Term Loan Agreement.

The 2015 Term Loan Agreement provides that outstanding borrowings bear interest at 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, 2016, the applicable margin for LIBOR-based borrowings under the 2015 Term Loan Agreement was 1.375% based on our credit ratings. As of December 31, 2016, the weighted average interest rate of the 2015 Term Loan Agreement was 1.86%.

The 2015 Term Loan Agreement contains substantially the same covenants as the Revolving Credit Facility.

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 Agreement, the EOIT $250 million variable rate term loan, 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 guaranteed collection of the Partnership’s obligations under the 2019 Notes and 2024 Notes. The guarantee expired on May 1, 2016. The 2019 Notes, 2024 Notes and 2044 Notes have a $1 million unamortized discount and $10 million of unamortized debt expense at December 31, 2016, resulting in effective interest rates of 2.59%, 4.02% and 5.09%, respectively, during the year ended December 31, 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, 2016, 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 an $18 million unamortized premium at December 31, 2016, resulting in an effective interest rate of 3.83% during the year ended December 31, 2016. 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 $15 million and $18 million at December 31, 2016 and 2015, respectively, is classified as either a reduction to Long-Term Debt or Other Assets in the Consolidated Balance Sheets and is being amortized over the life of the respective debt. Unamortized premium, net of unamortized discount on long-term debt of $17 million and $23 million at December 31, 2016 and 2015, 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 Agreement and the EOIT $250 million variable rate term loan, which is included in Other, net on the Consolidated Statements of Income.

As of December 31, 2016, the Partnership and EOIT were in compliance with all of their debt agreements, including financial covenants.

Fair Value Measurements

12 Months Ended

Dec. 31, 2016

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 oil 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, 2016, there were no transfers between Level 2 and Level 3 instruments.

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, 2016 and 2015:



	December 31, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-Term Debt
Long-term notes payable—affiliated companies (Level 2)	$	—	$	—	$	363	$	350
Revolving Credit Facility (Level 2)⁽¹⁾	636		636		310		310
2015 Term Loan Agreement (Level 2)	450		450		450		450
EOIT Senior Notes (Level 2)	268		260		273		280
Enable Midstream Partners, LP, 2019, 2024 and 2044 Notes (Level 2)	1,649		1,521		1,650		1,255

___________________


(1)	Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. There was zero and $236 million of commercial paper outstanding as of December 31, 2016 and 2015, respectively.

The fair value of the Partnership’s Long-term notes payable—affiliated companies, Revolving Credit Facility, and 2015 Term Loan Agreement, 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, 2016, 2015 and 2014, the Partnership remeasured the Service Star assets at fair value. At December 31, 2016, 2015 and 2014, management reassessed the carrying value of the Service Star business line, a component of the gathering and processing segment that provides measurement and communication services to third parties. The 2016 impairment, which impaired substantially all of the remaining net book value of the Service Star business line, was primarily driven by the impact of planned technology changes affecting Service Star. The 2015 impairment was based upon higher than expected losses of customers and the 2014 impairment was due to decreases of crude oil and natural gas prices. 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 forecasted 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, 2016, 2015 and 2014, the Partnership recognized a $9 million, $10 million and $7 million impairment, respectively. The $9 million consisted of an $8 million write-down of property, plant and equipment and a $1 million write-down of materials and supplies inventory considered either excess or obsolete. The $10 million impairment consisted of a $9 million write-down of property, plant 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.

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, 2016 and 2015:



December 31, 2016	Commodity Contracts				Gas Imbalances ⁽¹⁾
	Assets		Liabilities		Assets ⁽²⁾		Liabilities ⁽³⁾
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	2	$	22	$	—	$	—
Significant other observable inputs (Level 2)	—		4		41		30
Unobservable inputs (Level 3)	—		8		—		—
Total fair value	2		34		41		30
Netting adjustments	—		—		—		—
Total	$	2	$	34	$	41	$	30



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

______________________

(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, 2016 and 2015.


(2)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of zero and $6 million at December 31, 2016 and 2015, 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 at each of December 31, 2016 and 2015, 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
Losses included in earnings	—			(13		)
Settlements	—			1
Transfers out of Level 3	—			—
Balance as of December 31, 2016	$	—		$	(8	)

______________________


(1)	The Partnership utilizes WTI crude oil swaps to manage exposure to condensate price risk. As the over-the-counter WTI crude oil swap is an active market, these derivative instruments were 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, 2016
Product Group	Fair Value			Forward Curve Range
	(In millions)			(Per gallon)
Natural gas liquids	$	(8	)	$0.385 - $0.936

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, 2016

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 oil 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 natural gas exposure associated with its gathering, processing and 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, 2016 and 2015, 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, 2016 and 2015, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:



	December 31, 2016		December 31, 2015
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas—TBtu⁽¹⁾
Financial fixed futures/swaps	2	29	1	37
Financial basis futures/swaps	2	30	4	38
Physical purchases/sales	1	25	2	51
Crude oil (for condensate)—MBbl⁽²⁾
Financial futures/swaps	—	540	—	506
Natural gas liquids—MBbl⁽³⁾
Financial futures/swaps	60	1,133	75	1,011

____________________


(1)	As of December 31, 2016, 100% of the natural gas contracts have durations of one year or less. As of December 31, 2015, 97.7% of the natural gas contracts had durations of one year or less and 2.3% had durations of more than one year and less than two years.


(2)	As of December 31, 2016 and 2015, 100% of the crude oil (for condensate) contracts have durations of one year or less.


(3)	As of December 31, 2016 and 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, 2016 and 2015 that were not designated as hedging instruments for accounting purposes are as follows:



		December 31, 2016				December 31, 2015
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	2	$	22	$	17	$	3
Physical purchases/sales	Other Current	—		1		1		—
Crude oil (for condensate)
Financial futures/swaps	Other Current	—		3		9		—
Natural gas liquids
Financial futures/swaps	Other Current	—		8		4		—
Total gross derivatives ⁽¹⁾		$	2	$	34	$	31	$	3

_____________________


(1)	See Note 11 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheets as of December 31, 2016 and 2015.

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, 2016, 2015 and 2014:



	Amounts Recognized in Income
	Year Ended December 31,
	2016			2015			2014
	(In millions)
Natural gas financial futures/swaps gains (losses)	$	(19	)	$	26		$	37
Natural gas physical purchases/sales gains (losses)	(7		)	(9		)	1
Crude oil (for condensate) financial futures/swaps gains (losses)	(4		)	12			9
Natural gas liquids financial futures/swaps gains (losses)	(13		)	10			2
Total	$	(43	)	$	39		$	49

For derivatives not designated as hedges in the tables above, amounts recognized in income for the years ended December 31, 2016, 2015 and 2014, if any, are reported in Product sales.

The following table presents the components of gain (loss) on derivative activity in the Partnership’s Consolidated Statements of Income for the years ended December 31, 2016, 2015 and 2014:



	Year Ended December 31,
	2016			2015			2014
	(In millions)
Change in fair value of derivatives	$	(60	)	$	(8	)	$	38
Realized gain on derivatives	17			47			11
Gain (loss) on derivative activity	$	(43	)	$	39		$	49

Credit-Risk Related Contingent Features in Derivative Instruments

Based upon the Partnership’s senior unsecured debt rating with Moody’s Investors Services or Standard & Poor’s Ratings Services, the Partnership could be required to provide credit assurances to third parties, which could include letters of credit or cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position. As of December 31, 2016, under these obligations, $3 million of cash collateral has been posted. Based on positions as of December 31, 2016, there was no additional collateral required to be posted by the Partnership.

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.

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Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information

12 Months Ended

Dec. 31, 2016

Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:



	Year Ended December 31,
	2016		2015		2014
	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	105	$	85	$	77
Income taxes, net of refunds	—		1		1
Non-cash transactions:
Accounts payable related to capital expenditures	18		52		93
Issuance of common units upon interest acquisition of SESH (Note 9)	—		1		161

The following table reconciles cash and cash equivalents and restricted cash on the Consolidated Balance Sheets to cash, cash equivalents and restricted cash on the Consolidated Statement of Cash Flows:



	2016
	(In millions)
Cash and cash equivalents	$	6
Restricted cash	17
Cash, cash equivalents and restricted cash shown in the Consolidated Statement of Cash Flows	$	23

Related Party Transactions

12 Months Ended

Dec. 31, 2016

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.

Transportation and Storage Agreements

Transportation and Storage Agreements with CenterPoint Energy

EGT provides the following services to CenterPoint Energy’s LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas: (1) firm transportation with seasonal contract demand, (2) firm storage, (3) no notice transportation with associated storage and (4) maximum rate firm transportation. The first three services are in effect through March 31, 2021, and will remain in effect from year to year thereafter unless either party provides 180 days’ written notice prior to the contract termination date. The maximum rate firm transportation is in effect through March 31, 2018. MRT provides firm transportation and firm storage services to CenterPoint Energy’s LDCs under agreements that are in effect through May 15, 2018, but will continue year to year thereafter unless either party provides twelve months’ written notice prior to the contract termination date.

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 reimbursed CenterPoint Energy’s Arkansas LDC approximately $7 million dollars for cost incurred in connecting the LDC to EGT’s new pipeline segment.

Transportation and Storage Agreement with OGE Energy

EOIT provides no-notice load-following transportation and storage services to OGE Energy. On March 17, 2014, EOIT entered into a transportation agreement with OGE Energy, with a primary term of May 1, 2014 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.

On December 6, 2016, EOIT entered into a transportation agreement with OGE Energy, with a primary term expected to begin in late 2018 and extend for 20 years. In connection with the agreement, an approximately 80 mile pipeline will be built to serve OGE Energy’s Muskogee Power Plant.

Gas Sales and Purchases Transactions

The Partnership sells natural gas volumes to affiliates of CenterPoint Energy and OGE Energy or purchase natural gas volumes from affiliates of CenterPoint Energy through a combination of forward, monthly and daily transactions. The Partnership enters into these physical natural gas transactions in the normal course of business based upon relevant market prices.

The Partnership’s revenues from affiliated companies accounted for 7%, 7% and 6% of revenues during the years ended December 31, 2016, 2015 and 2014, respectively.

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



	Year Ended December 31,
	2016		2015		2014
	(In millions)
Gas transportation and storage service revenue — CenterPoint Energy	$	110	$	110	$	112
Natural gas product sales — CenterPoint Energy	1		7		22
Gas transportation and storage service revenue — OGE Energy	36		37		39
Natural gas product sales — OGE Energy	12		8		13
Total revenues — affiliated companies	$	159	$	162	$	186

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



	Year Ended December 31,
	2016		2015		2014
	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	—	$	2	$	2
Cost of natural gas purchases — OGE Energy	14		15		19
Total cost of natural gas purchases — affiliated companies	$	14	$	17	$	21

Corporate services and seconded employee expense

For the year ended December 31, 2014, the Partnership’s employees were seconded by CenterPoint Energy and OGE Energy, and the Partnership reimbursed 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 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.

Under the terms of the MFA, the Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under service agreements for an initial term that ended 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 prior to the end of any extension. 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 2016 are $7 million and $6 million, respectively.

On November 1, 2016, the Partnership entered into a new lease with an affiliate of CenterPoint Energy pursuant to which the Partnership leases office space in Shreveport, Louisiana. The term of the lease was effective on October 1, 2016 and extends through December 31, 2019. The Partnership expects to incur approximately $3 million in rent and maintenance expenses through the end of the initial term of the lease. Prior to October 1, 2016, CenterPoint Energy provided the office space in Shreveport, Louisiana under the services agreement. As of December 31, 2016, CenterPoint Energy continues to provide office and data center space to the Partnership in Houston, Texas under the services agreement.

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 Consolidated Statements of Income are as follows:



	Year Ended December 31,
	2016		2015		2014
	(In millions)
Seconded Employee Costs - CenterPoint Energy	$	—	$	—	$	138
Corporate Services - CenterPoint Energy	6		15		29
Seconded Employee Costs - OGE Energy	29		35		105
Corporate Services - OGE Energy	5		11		17
Total corporate services and seconded employees expense	$	40	$	61	$	289

Series A Preferred Units

Notes payable

The Partnership had outstanding long-term notes payable—affiliated companies to CenterPoint Energy at December 31, 2015 of $363 million, which were scheduled to mature in 2017. On February 18, 2016, in connection with the private placement of the Series A Preferred Units, the Partnership redeemed the $363 million of notes payable—affiliated companies payable to a subsidiary of CenterPoint Energy.

The Partnership recorded affiliated interest expense to CenterPoint Energy on note payable—affiliated companies of $1 million, $8 million and $8 million during the years ended December 31, 2016, 2015 and 2014, respectively.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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,
	2017		2018		2019		2020		2021		After 2021		Total
	(In millions)
Noncancellable operating leases	$	10	$	4	$	3	$	—	$	—	$	—	$	17

Total rental expense for all operating leases was $27 million, $32 million and $23 million during the years ended December 31, 2016, 2015 and 2014, 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 Consolidated Statements of Income.

The Partnership currently has 78 compression service agreements, of which 40 agreements are on a month-to-month basis, 32 agreements will expire in 2017 and 6 agreements will expire in 2018. The Partnership also has 6 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 Consolidated Statements of Income.

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, 2016

Income Tax Disclosure [Abstract]

Income Taxes

The Partnership’s earnings are generally not subject to income tax (other than Texas state margin taxes and taxes associated with the Partnership’s corporate subsidiaries, Enable Midstream Services and Enable Muskogee Intrastate Transmission) 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 consolidated financial statements. Consequently, the Consolidated Statements of Income do not include an income tax provision (other than Texas state margin taxes and taxes associated with the Partnership’s corporate subsidiaries).

The items comprising income tax expense are as follows:



	Year Ended December 31,
	2016			2015			2014
	(In millions)
Provision (benefit) for current income taxes
Federal	$	(1	)	$	—		$	—
State	—			1			1
Total provision (benefit) for current income taxes	(1		)	1			1
Provision (benefit) for deferred income taxes, net
Federal	$	3		—			$	—
State	(1		)	(1		)	1
Total provision (benefit) for deferred income taxes, net	2			(1		)	1
Total income tax expense	$	1		$	—		$	2

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



	Year Ended December 31,
	2016			2015			2014
	(In millions)
Income (loss) before income taxes	$	314		$	(771	)	$	535
Federal statutory rate	—		%	—		%	—		%
Expected federal income tax expense	—			—			—
Increase in tax expense resulting from:
State income taxes, net of federal income tax	1			—			2
Total	1			—			2
Total income tax expense	$	1		$	—		$	2
Effective tax rate	0.3		%	—		%	0.4		%

The components of Deferred Income Taxes as of December 31, 2016 and 2015 were as follows:



	December 31,
	2016		2015
	(In millions)
Deferred tax assets:	$	—	$	—
Deferred tax liabilities:
Non-current:
Depreciation	7		9
Other	3		(1		)
Total non-current deferred tax liabilities	10		8
Accumulated deferred income taxes, net	$	10	$	8

Uncertain Income Tax Positions

There were no unrecognized tax benefits as of December 31, 2016, 2015 and 2014.

Tax Audits and Settlements

The federal income tax return of the Partnership has been audited through the 2013 tax year.

Equity Based Compensation

12 Months Ended

Dec. 31, 2016

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 (LTIP) for officers, directors and employees of the Partnership and its affiliates, including any individual who provides services to the Partnership as a seconded employee. The long-term incentive plan provides for the following types of awards: restricted units, phantom units, appreciations rights, option rights, cash incentive awards, performance units, distribution equivalent rights, and other awards denominated in, payable in, valued in or otherwise based on or related to common units.

The long-term incentive plan is administered by the Compensation Committee of the Board of Directors. With respect to any grant of equity as long-term incentive awards to our independent directors and our officers subject to reporting under Section 16 of the Exchange Act, the Compensation Committee makes recommendations to the Board of Directors and any such awards will only be effective upon the approval of the Board of Directors. The long-term incentive plan limits 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 are available for delivery pursuant to other awards.

The Board of Directors may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made, including amending the long-term incentive plan to increase the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would be adverse to the participant without the consent of the participant.

The following table summarizes the Partnership’s equity based compensation expense for the years ended December 31, 2016, 2015 and 2014 related to performance units, restricted units and phantom units for the Partnership’s employees and independent directors:



	Year Ended December 31,
	2016		2015		2014
	(In millions)
Performance units	$	9	$	3	$	3
Restricted units	3		7		10
Phantom units	1		1		2
Total compensation expense	$	13	$	11	$	15

Performance Units

Awards of performance based phantom units (performance units) have been made under the LTIP in 2016, 2015 and 2014 to certain officers and employees providing services to the Partnership. Subject to the achievement of performance goals, the performance unit awards cliff vest three years from the grant date, with distribution equivalent rights paid at vesting. The performance goals for 2016, 2015 and 2014 awards are based on total unitholder return over a three calendar year performance cycle. Total unitholder return is based on the relative performance of the Partnership’s common units against a peer group. The performance unit awards have a payout from 0% to 200% of the target based on the level of achievement of the performance goal. Performance units awards are paid out in common units, with distribution equivalent rights paid in cash at vesting. Any unearned performance units are cancelled. Pay out requires the confirmation of the achievement of the performance level by the Compensation Committee. Prior to vesting, performance units are subject to forfeiture if the recipient’s employment with the Partnership is terminated for any reason other than death, disability, retirement or termination other than for cause within two years of a change in control. 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. Performance unit awards are classified as equity on the Partnership’s Consolidated Balance Sheet.

The fair value of each performance unit award was estimated on the grant date using a lattice-based valuation model. The valuation information factored into the model includes 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 each performance unit award 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 included in the fair value calculation of the performance unit award. Due to the short trading history of the Partnership’s common units, the expected price volatility for the awards granted in 2016 is based on two years of daily stock price observations, combined with the average of the one-year volatility of the applicable peer group companies used to determine the total unitholder return ranking. The expected price volatility for the awards granted in 2015 is based on one year of daily stock price observations, combined with the average of the two-year volatility of the applicable peer group companies used to determine the total unitholder return ranking. The expected price volatility for the awards granted in 2014 is based on the average of the two-year volatility of the applicable 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.



	2016	2015			2014
Number of units granted	1,235,429	501,474			563,963
Fair value of units granted	$10.42 - $27.77	$	16.59		$	29.61
Expected price volatility	43.2% - 46.0%	27.6		%	22.2		%
Risk-free interest rate	0.86% - 0.90%	0.99		%	0.83		%
Expected life of units (in years)	3.00	3.00			3.00

Phantom Units

Awards of phantom units have been made under the LTIP in 2016, 2015 and 2014 to certain officers and employees providing services to the Partnership and certain directors of Enable GP. In 2014, 100,000 phantom units were awarded to certain officers and employees providing services to the Partnership that vested on the first anniversary of the grant date with distribution equivalent rights paid at vesting. Also in 2014, 6,718 phantom units were awarded to the independent directors for their service as directors that vested on the first anniversary of the grant date with distribution equivalent rights paid during the vesting period. In 2015, 9,817 phantom units were granted to employees providing services to the Partnership that vest on the first, second or third anniversary of the grant date with distribution equivalent rights paid during the vesting period. In April 2016, 653,286 phantom units were awarded to certain officers and employees providing services to the Partnership that vest on the first, second or third anniversary of the award with distribution equivalent rights paid during the vesting period. Phantom units awards are paid out in common units, with distributions equivalent rights paid in cash. Phantom units cliff-vest at the end of the vesting period. Any unearned phantom units are cancelled. Prior to vesting, phantom units are subject to forfeiture if the recipient’s employment with the Partnership is terminated for any reason other than death, disability, retirement or termination other than for cause within two years of a change in control. Phantom unit awards are classified as equity on the Partnership’s Consolidated Balance Sheet.

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 the vesting period. Distributions on phantom units are either accumulated and paid at vesting or paid during the vesting period and, therefore, are included in the fair value calculation. The expected life of the phantom unit is based on the applicable vesting period. The number of phantom units granted and the grant date fair value are shown in the following table.



	2016	2015		2014
Phantom units granted	653,286	9,817		106,718
Fair value of phantom units granted	$8.12 - $15.30	$	12.70	$23.16 - $23.70

Restricted Units

Awards of restricted units were made under the LTIP in 2015 and 2014 to certain officers and employees providing services to the Partnership and certain directors of Enable GP. These restricted unit awards cliff vest on the first, second, third or fourth anniversary of grant date, with distribution equivalent rights paid during the vesting period. Restricted units are outstanding and issued common units that cannot be sold, assigned, transferred or pledged by the recipient prior to vesting. Any unearned restricted units are cancelled. Prior to vesting, restricted units are subject to forfeiture if the recipient ceases to render substantial services to the Partnership for any reason other than death, disability, retirement or termination other than for cause within two years of a change in control.

In 2014, 375,000 restricted units were granted to Lynn Bourdon, who was then 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; 150,000 restricted units to Mr. Bourdon, of which 50% vested on May 29, 2015 and 50% was forfeited upon his departure; 137,500 restricted units were granted to Rodney J. Sailor, who was then the Chief Financial Officer of Enable GP, of which 45.46% vested on March 1, 2015 and 54.54% vested on March 1, 2016; 25,000 restricted units were granted to Mr. Sailor, which vest four years from the grant date; and 304,901 restricted units were granted to officers and employees providing services to the Partnership which vest on the first, second, third or fourth anniversary of grant date. In 2015, 279,677 restricted units were granted to officers and employees providing services to the Partnership which vest on the first, second, or third anniversary of 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. Restricted unit awards are classified as equity on the Partnership’s Consolidated Balance Sheet.

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.

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

Other Awards

In 2016 and 2015, the Board of Directors granted 14,914 and 17,384 common units, respectively, to the independent directors of Enable GP, for their service as directors, which vested immediately. The fair value of the common units were based on the closing market price of the Partnership’s common unit on the grant date.



	2016		2015
Common units granted	14,914		17,384
Fair value of common units granted	$	15.35	$	11.12

Units Outstanding

A summary of the activity for the Partnership’s performance units, restricted units and phantom units as of December 31, 2016 and changes during 2016 are shown in the following table.



	Performance Units					Restricted Stock					Phantom Units
	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 12/31/2015	814,510			$	22.16	581,772			$	21.04	9,817			$	12.70
Granted⁽¹⁾	1,235,429			10.80		—			—		653,286			8.45
Vested	(6,427		)	20.77		(125,843		)	22.78		(5,594		)	12.44
Forfeited	(74,405		)	15.94		(62,934		)	19.43		(13,905		)	8.12
Units Outstanding at 12/31/2016	1,969,107			15.27		392,995			20.74		643,604			8.49
Aggregate Intrinsic Value of Units Outstanding at 12/31/2016	$	31				$	6				$	10

_____________________


(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, 2016 are shown in the following table.



	December 31, 2016
	Performance Units		Restricted Stock		Phantom Units
	(In millions)
Aggregate Intrinsic Value of Units Vested	$	—	$	1	$	—
Fair Value of Units Vested	—		3		—

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, 2016
	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance Units	$	15	1.81
Restricted Units	2		1.12
Phantom Units	4		2.20
Total	$	21

As of December 31, 2016, there were 9,307,350 units available for issuance under the long term incentive plan.

Reportable Segments

12 Months Ended

Dec. 31, 2016

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. 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.

Financial data for reportable segments are as follows:



Year Ended December 31, 2016	Gathering and Processing		Transportation and Storage ⁽¹⁾		Eliminations			Total
	(In millions)
Product sales	$	1,081	$	479	$	(388	)	$	1,172
Service revenue	559		545		(4		)	1,100
Total Revenues⁽²⁾	1,640		1,024		(392		)	2,272
Cost of natural gas and natural gas liquids	915		492		(390		)	1,017
Operation and maintenance, General and administrative	276		191		(2		)	465
Depreciation and amortization	212		126		—			338
Impairments	9		—		—			9
Taxes other than income tax	32		26		—			58
Operating income	$	196	$	189	$	—		$	385
Total assets	$	7,453	$	4,963	$	(1,204	)	$	11,212
Capital expenditures	$	312	$	71	$	—		$	383



Year Ended December 31, 2015	Gathering and Processing			Transportation and Storage ⁽¹⁾			Eliminations			Total
	(In millions)
Product sales	$	1,118		$	590		$	(374	)	$	1,334
Service revenue	545			542			(3		)	1,084
Total 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	$	(306	)	$	(406	)	$	—		$	(712	)
Total assets	$	7,536		$	4,976		$	(1,286	)	$	11,226
Capital expenditures	$	839		$	110		$	—		$	949



Year Ended December 31, 2014	Gathering and Processing		Transportation and Storage⁽¹⁾		Eliminations			Total
	(In millions)
Product sales	$	1,907	$	1,009	$	(616	)	$	2,300
Service revenue	517		568		(18		)	1,067
Total 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

_____________________


(1)	Equity in earnings of equity method affiliate is included in Other Income (Expense) on the Consolidated Statements of Income, and is not included in the table above. 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, 2016, 2015 and 2014.


(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.

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Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2016 and 2015 are as follows:



	Quarters Ended
	March 31, 2016		June 30, 2016		September 30, 2016			December 31, 2016
	(in millions, except per unit data)
Total Revenues	$	509	$	529	$	620		$	614
Cost of natural gas and natural gas liquids	195		254		268			300
Operating income	103		57		139			86
Net income	86		39		119			69
Net income attributable to limited partners	86		39		119			68
Net income attributable to common and subordinated units	86		35		110			59

Basic earnings per unit
Common units	$	0.21	$	0.08	$	0.26		$	0.14
Subordinated units	$	0.20	$	0.08	$	0.26		$	0.14
Diluted earnings per unit
Common units	$	0.19	$	0.08	$	0.26		$	0.14
Subordinated units	$	0.20	$	0.08	$	0.26		$	0.14

	Quarters Ended
	March 31, 2015		June 30, 2015		September 30, 2015			December 31, 2015
	(in millions, except per unit data)
Total 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 limited partners	91		77		(985		)	65
Net income (loss) attributable to common and subordinated units	91		77		(985		)	65

Basic earnings (loss) per unit
Common Units	$	0.22	$	0.18	$	(2.33	)	$	0.15
Subordinated units	$	0.21	$	0.18	$	(2.34	)	$	0.15
Diluted earnings (loss) per unit
Common Units	$	0.22	$	0.18	$	(2.33	)	$	0.15
Subordinated units	$	0.21	$	0.18	$	(2.34	)	$	0.15

_____________________

(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 (Policies)

12 Months Ended

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization

Basis of Presentation

The accompanying consolidated financial statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP.

Use of Estimates

Revenue Recognition

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

Natural Gas and Natural Gas Liquids Purchases

Operation and Maintenance and General and Administrative Expense

Environmental Costs

Depreciation and Amortization

Depreciation and Amortization Expense

Income Taxes

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.

Restricted Cash

Restricted cash consists of cash which is restricted by agreements with third parties.

Accounts Receivable and Allowance for Doubtful Accounts

Inventory

Gas Imbalances

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

Long-Lived Assets (including Intangible Assets)

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

Regulatory Assets and Liabilities

Capitalization of Interest and Allowance for Funds Used During Construction

Derivative Instruments

Commodity Price Risk


•	NGL put options, NGL futures and swaps, and WTI crude oil 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 natural gas exposure associated with its gathering, processing and 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.

As of December 31, 2016 and 2015, the Partnership had no derivative instruments that were designated as cash flow or fair value hedges for accounting purposes.

Credit Risk

Derivatives Not Designated As Hedging Instruments

Quantitative Disclosures Related to Derivative Instruments

Fair Value Measurements

Quantitative Information on Level 3 Fair Value Measurements

Equity Based Compensation

New Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which supersedes the revenue recognition requirements in “Revenue Recognition (Topic 605).” Topic 606 is based on the core principle that revenue is recognized to depict 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. Topic 606 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract.

Topic 606 is effective for fiscal years beginning after December 15, 2017, and interim periods within those years, with early adoption permitted in 2017, however we do not plan to adopt the standard early. Entities will have the option to apply the standard using a full retrospective or modified retrospective adoption method. The Partnership expects to adopt this ASU using the modified retrospective method. Our evaluation of the impact on our Consolidated Financial Statements and related disclosures is ongoing and not complete. In connection with our assessment work, we formed an implementation work team, completed training on the Topic 606 revenue recognition model and are continuing our review of contracts relative to the provisions of Topic 606.

Leases

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” This standard requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Partnership expects to adopt this standard in the first quarter of 2019 and is currently evaluating the impact of this standard on our Consolidated Financial Statements and related disclosures. In connection with our assessment work, we formed an implementation work team and are continuing a review of our contracts relative to the provisions of the lease standard.

Share-Based Compensation

In March 2016, the FASB issued ASU No. 2016-09, “Compensation—Stock Compensation (Topic 718).” This standard makes several modifications to Topic 718 related to the accounting for forfeitures, employer tax withholding on share-based compensation and the financial statement presentation of excess tax benefits or deficiencies. ASU 2016-09 also clarifies the statement of cash flows presentation for certain components of share-based awards. The standard is effective for interim and annual reporting periods beginning in 2017, although early adoption is permitted. The Partnership will adopt the amendment in the fourth quarter of 2017, and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

Financial Instruments—Credit Losses

In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This standard requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions and reasonable and supportable forecasts in order to record credit losses in a more timely matter. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. The guidance requires application using a modified retrospective method. The Partnership does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

Statement of Cash Flows

In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” This standard is intended to reduce existing diversity in practice in how certain transactions are presented on the statement of cash flows. The standard is effective for interim and annual reporting periods beginning after December 15, 2017, although early adoption is permitted. The guidance requires application using a retrospective transition method. The Partnership will adopt ASU No. 2016-15 in the first quarter of 2017 and has determined the amendment will not have a material impact on our Consolidated Financial Statements and related disclosures.

Income Taxes

In October 2016, the FASB issued ASU No. 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory.” This standard requires entities to recognize the tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The standard is effective for interim and annual reporting periods beginning after December 15, 2017, although early adoption is permitted as of the beginning of an annual period (i.e., only in the first interim period). The guidance requires application using a modified retrospective approach. The Partnership is currently evaluating the impact, if any, the adoption of this standard will have on our Consolidated Financial Statements and related disclosures.

Restricted Cash

In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash.” The standard is intended to provide specific guidance on the cash flow classification and presentation of changes in restricted cash. The Partnership early adopted the amendment in the fourth quarter of 2016, using a retrospective basis. As of December 31, 2016, the Partnership had restricted cash of $17 million. The Partnership had no restricted cash as of December 31, 2015.

Contracts with Master Netting Arrangements

Reportable Segments

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

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 Consolidated Statements of Income.



	December 31,
	2016		2015
	(In millions)
Materials and supplies	$	30	$	34
Natural gas and natural gas liquids inventories	11		19
Total	$	41	$	53

Acquisition (Tables)

12 Months Ended

Dec. 31, 2016

Business Combinations [Abstract]

Schedule of Assets Acquired and Liabilities Assumed



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

Earnings Per Limited Partner Unit (Tables)

12 Months Ended

Dec. 31, 2016

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 units:



	Year Ended December 31,
	2016		2015			2014
	(In millions, except per unit data)
Net income (loss)	$	313	$	(771	)	$	533
Net income (loss) attributable to noncontrolling interest	1		(19		)	3
Series A Preferred Unit distribution	22		—			—
General partner interest in net income	—		—			—
Net income (loss) available to common and subordinated unitholders	$	290	$	(752	)	$	530

Net income (loss) allocable to common units	$	148	$	(381	)	$	339
Net income (loss) allocable to subordinated units	142		(371		)	191
Net income (loss) available to common and subordinated unitholders	$	290	$	(752	)	$	530

Net income (loss) allocable to common units	$	148	$	(381	)	$	339
Dilutive effect of Series A Preferred Unit distribution	—		—			—
Dilutive effect of performance units	—		—			—
Diluted net income (loss) allocable to common units	148		(381		)	339
Diluted net income (loss) allocable to subordinated units	142		(371		)	191
Total	$	290	$	(752	)	$	530

Basic weighted average number of outstanding
Common units	216		214			264
Subordinated units	208		208			148
Total	424		422			412

Basic earnings (loss) per unit
Common units	$	0.69	$	(1.78	)	$	1.29
Subordinated units	$	0.68	$	(1.78	)	$	1.28

Basic weighted average number of outstanding common units	216		214			264
Dilutive effect of Series A Preferred Units	—		—			—
Dilutive effect of performance units	—		—			—
Diluted weighted average number of outstanding common units	216		214			264
Diluted weighted average number of outstanding subordinated units	208		208			148
Total	424		422			412

Diluted earnings (loss) per unit
Common units	$	0.69	$	(1.78	)	$	1.29
Subordinated units	$	0.68	$	(1.78	)	$	1.28

Enable Midstream Partners, LP Partners' Equity (Tables)

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

Schedule Of Equity Transactions With Limited Partner

The Partnership paid or has authorized payment of the following cash distributions to common and subordinated unitholders during 2016, 2015 and 2014 (in millions, except for per unit amounts):



Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
December 31, 2016⁽¹⁾	February 21, 2017	February 28, 2017	$	0.318	$	137
September 30, 2016	November 14, 2016	November 22, 2016	$	0.318	$	134
June 30, 2016	August 16, 2016	August 23, 2016	$	0.318	$	134
March 31, 2016	May 6, 2016	May 13, 2016	$	0.318	$	134
December 31, 2015	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 February 10, 2017, to be paid on February 28, 2017, to common and subordinated unitholders of record at the close of business on February 21, 2017.


(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 IPO, April 16, 2014 through June 30, 2014.

Schedule of Cash Distributions to Series A Preferred Unitholders

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2016 (in millions, except for per unit amounts):



Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
December 31, 2016⁽¹⁾	February 10, 2017	February 15, 2017	$	0.625	$	9
September 30, 2016	November 1, 2016	November 14, 2016	$	0.625	$	9
June 30, 2016	August 2, 2016	August 12, 2016	$	0.625	$	9
March 31, 2016⁽²⁾	May 6, 2016	May 13, 2016	$	0.2917	$	4

_____________________


(1)	The board of directors of Enable GP declared this $0.625 per Series A Preferred Unit cash distribution on February 10, 2017, which was paid on February 15, 2017 to Series A Preferred unitholders of record at the close of business on February 10, 2017.


(2)	The prorated quarterly distribution for the Series A Preferred Units is for a partial period beginning on February 18, 2016, and ending on March 31, 2016, which equates to $0.625 per unit on a full-quarter basis or $2.50 per unit on an annualized basis.

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2016

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)	2016		2015
		(In millions)
Property, plant and equipment, gross:
Gathering and Processing	37	$	6,987	$	6,478
Transportation and Storage	36	4,498		4,444
Construction work-in-progress		82		371
Total		$	11,567	$	11,293
Accumulated depreciation:
Gathering and Processing		681		510
Transportation and Storage		743		652
Total accumulated depreciation		1,424		1,162
Property, plant and equipment, net		$	10,143	$	10,131

Intangible Assets, Net (Tables)

12 Months Ended

Dec. 31, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Finite-Lived Intangible Assets

Intangible assets consist of the following:



	December 31,
	2016		2015
	(In millions)
Customer relationships:
Total intangible assets	$	405	$	405
Accumulated amortization	99		72
Net intangible assets	$	306	$	333

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:



	2017		2018		2019		2020		2021
	(In millions)
Expected amortization of intangible assets	$	27	$	27	$	27	$	27	$	27

Goodwill (Tables)

12 Months Ended

Dec. 31, 2016

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

Balance as of December 31, 2016	$	—		$	—		$	—

Investment in Equity Method Affiliate (Tables)

12 Months Ended

Dec. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Investments Detail

Investment in Equity Method Affiliate:



	(In millions)
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⁽¹⁾	(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⁽¹⁾	(42		)
Balance as of December 31, 2015	344
Equity in earnings of equity method affiliate	28
Distributions from equity method affiliate⁽¹⁾	(43		)
Balance as of December 31, 2016	$	329

____________________


(1)	Distributions from equity method affiliate includes a $28 million, $34 million and $23 million return on investment and a $15 million, $8 million and zero return of investment for the years ended December 31, 2016, 2015 and 2014, respectively.

Equity in Earnings of Equity Method Affiliate:



	Year Ended December 31,
	2016		2015		2014
	(In millions)
SESH	$	28	$	29	$	20

Distributions from Equity Method Affiliate:



	Year Ended December 31,
	2016		2015		2014
	(In millions)
SESH ⁽¹⁾	$	43	$	42	$	23

_____________________


(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:



	December 31,
	2016			2015
	(In millions)
Balance Sheet Data:
Current assets	$	31		$	45
Property, plant and equipment, net	1,110			1,127
Total assets	$	1,141		$	1,172
Current liabilities	$	18		$	18
Long-term debt	397			397
Members’ equity	726			757
Total liabilities and members’ equity	$	1,141		$	1,172
Reconciliation:
Investment in SESH	$	329		$	344
Less: Capitalized interest on investment in SESH	(1		)	(1		)
Add: Basis differential, net of amortization	35			36
The Partnership’s share of members’ equity	$	363		$	379



	Year Ended December 31,
	2016		2015		2014
	(In millions)
Income Statement Data:
Revenues	$	115	$	115	$	108
Operating income	$	73	$	71	$	69
Net income	$	55	$	57	$	48

Debt (Tables)

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Schedule of Debt

The following table presents the Partnership’s outstanding debt as of December 31, 2016 and 2015.



	December 31,
	2016		2015
	(In millions)
Commercial Paper	$	—	$	236
Revolving Credit Facility	636		310
2015 Term Loan Agreement	450		450
Notes payable—affiliated companies (Note 14)	—		363
2019 Notes	500		500
2024 Notes	600		600
2044 Notes	550		550
EOIT Senior Notes	250		250
Premium (Discount) on long-term debt	17		23
Total debt	3,003		3,282
Less: Short-term debt⁽¹⁾	—		236
Less: Unamortized debt expense	10		12
Less: Notes payable—affiliated companies	—		363
Total long-term debt	$	2,993	$	2,671

___________________


(1)	There were no commercial paper borrowings outstanding as of December 31, 2016. Short-term debt includes $236 million of commercial paper as of December 31, 2015.

Schedule of Maturities of Long-term Debt

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



2017	$	—
2018	450
2019	500
2020	886
2021	—
Thereafter	1,150

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2016

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, 2016 and 2015:



	December 31, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-Term Debt
Long-term notes payable—affiliated companies (Level 2)	$	—	$	—	$	363	$	350
Revolving Credit Facility (Level 2)⁽¹⁾	636		636		310		310
2015 Term Loan Agreement (Level 2)	450		450		450		450
EOIT Senior Notes (Level 2)	268		260		273		280
Enable Midstream Partners, LP, 2019, 2024 and 2044 Notes (Level 2)	1,649		1,521		1,650		1,255

___________________


(1)	Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. There was zero and $236 million of commercial paper outstanding as of December 31, 2016 and 2015, 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, 2016 and 2015:



December 31, 2016	Commodity Contracts				Gas Imbalances ⁽¹⁾
	Assets		Liabilities		Assets ⁽²⁾		Liabilities ⁽³⁾
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	2	$	22	$	—	$	—
Significant other observable inputs (Level 2)	—		4		41		30
Unobservable inputs (Level 3)	—		8		—		—
Total fair value	2		34		41		30
Netting adjustments	—		—		—		—
Total	$	2	$	34	$	41	$	30



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

______________________

(1)


(2)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of zero and $6 million at December 31, 2016 and 2015, 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 at each of December 31, 2016 and 2015, 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, Net Derivative Asset (Liability) 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
Losses included in earnings	—			(13		)
Settlements	—			1
Transfers out of Level 3	—			—
Balance as of December 31, 2016	$	—		$	(8	)

______________________


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

Fair Value Inputs, Liabilities, Quantitative Information



	December 31, 2016
Product Group	Fair Value			Forward Curve Range
	(In millions)			(Per gallon)
Natural gas liquids	$	(8	)	$0.385 - $0.936

Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

As of December 31, 2016 and 2015, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:



	December 31, 2016		December 31, 2015
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas—TBtu⁽¹⁾
Financial fixed futures/swaps	2	29	1	37
Financial basis futures/swaps	2	30	4	38
Physical purchases/sales	1	25	2	51
Crude oil (for condensate)—MBbl⁽²⁾
Financial futures/swaps	—	540	—	506
Natural gas liquids—MBbl⁽³⁾
Financial futures/swaps	60	1,133	75	1,011

____________________


(1)	As of December 31, 2016, 100% of the natural gas contracts have durations of one year or less. As of December 31, 2015, 97.7% of the natural gas contracts had durations of one year or less and 2.3% had durations of more than one year and less than two years.


(2)	As of December 31, 2016 and 2015, 100% of the crude oil (for condensate) contracts have durations of one year or less.


(3)	As of December 31, 2016 and 2015, 100% of the natural gas liquid contracts have durations of one year or less.

Schedule of Derivative Assets at Fair Value



		December 31, 2016				December 31, 2015
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	2	$	22	$	17	$	3
Physical purchases/sales	Other Current	—		1		1		—
Crude oil (for condensate)
Financial futures/swaps	Other Current	—		3		9		—
Natural gas liquids
Financial futures/swaps	Other Current	—		8		4		—
Total gross derivatives ⁽¹⁾		$	2	$	34	$	31	$	3

_____________________


(1)	See Note 11 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheets as of December 31, 2016 and 2015.

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, 2016, 2015 and 2014:



	Amounts Recognized in Income
	Year Ended December 31,
	2016			2015			2014
	(In millions)
Natural gas financial futures/swaps gains (losses)	$	(19	)	$	26		$	37
Natural gas physical purchases/sales gains (losses)	(7		)	(9		)	1
Crude oil (for condensate) financial futures/swaps gains (losses)	(4		)	12			9
Natural gas liquids financial futures/swaps gains (losses)	(13		)	10			2
Total	$	(43	)	$	39		$	49

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location

The following table presents the components of gain (loss) on derivative activity in the Partnership’s Consolidated Statements of Income for the years ended December 31, 2016, 2015 and 2014:



	Year Ended December 31,
	2016			2015			2014
	(In millions)
Change in fair value of derivatives	$	(60	)	$	(8	)	$	38
Realized gain on derivatives	17			47			11
Gain (loss) on derivative activity	$	(43	)	$	39		$	49

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
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-Section 50
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-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 815
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-URI http://asc.fasb.org/extlink&oid=64837297&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=64837297&loc=d3e41678-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
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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=64837297&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=64837297&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41620-113959

Reference 10: 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, 2016

Schedule of Cash Flow, Supplemental Disclosures

The following table provides information regarding supplemental cash flow information:



	Year Ended December 31,
	2016		2015		2014
	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	105	$	85	$	77
Income taxes, net of refunds	—		1		1
Non-cash transactions:
Accounts payable related to capital expenditures	18		52		93
Issuance of common units upon interest acquisition of SESH (Note 9)	—		1		161

Schedule of Restricted Cash and Cash Equivalents



	2016
	(In millions)
Cash and cash equivalents	$	6
Restricted cash	17
Cash, cash equivalents and restricted cash shown in the Consolidated Statement of Cash Flows	$	23

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2016

Schedule of Revenues from Related Parties

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



	Year Ended December 31,
	2016		2015		2014
	(In millions)
Gas transportation and storage service revenue — CenterPoint Energy	$	110	$	110	$	112
Natural gas product sales — CenterPoint Energy	1		7		22
Gas transportation and storage service revenue — OGE Energy	36		37		39
Natural gas product sales — OGE Energy	12		8		13
Total revenues — affiliated companies	$	159	$	162	$	186

Schedule of Natural Gas Purchased From Related Parties

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



	Year Ended December 31,
	2016		2015		2014
	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	—	$	2	$	2
Cost of natural gas purchases — OGE Energy	14		15		19
Total cost of natural gas purchases — affiliated companies	$	14	$	17	$	21

Schedule of Amounts Charged to Partnership by Related Parties



	Year Ended December 31,
	2016		2015		2014
	(In millions)
Seconded Employee Costs - CenterPoint Energy	$	—	$	—	$	138
Corporate Services - CenterPoint Energy	6		15		29
Seconded Employee Costs - OGE Energy	29		35		105
Corporate Services - OGE Energy	5		11		17
Total corporate services and seconded employees expense	$	40	$	61	$	289

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Schedule of Future Minimum Rental Payments for Operating Leases

Future minimum payments for noncancellable operating leases are as follows:



	Year Ended December 31,
	2017		2018		2019		2020		2021		After 2021		Total
	(In millions)
Noncancellable operating leases	$	10	$	4	$	3	$	—	$	—	$	—	$	17

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

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,
	2016			2015			2014
	(In millions)
Provision (benefit) for current income taxes
Federal	$	(1	)	$	—		$	—
State	—			1			1
Total provision (benefit) for current income taxes	(1		)	1			1
Provision (benefit) for deferred income taxes, net
Federal	$	3		—			$	—
State	(1		)	(1		)	1
Total provision (benefit) for deferred income taxes, net	2			(1		)	1
Total income tax expense	$	1		$	—		$	2

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,
	2016			2015			2014
	(In millions)
Income (loss) before income taxes	$	314		$	(771	)	$	535
Federal statutory rate	—		%	—		%	—		%
Expected federal income tax expense	—			—			—
Increase in tax expense resulting from:
State income taxes, net of federal income tax	1			—			2
Total	1			—			2
Total income tax expense	$	1		$	—		$	2
Effective tax rate	0.3		%	—		%	0.4		%

Schedule of Deferred Tax Assets and Liabilities

The components of Deferred Income Taxes as of December 31, 2016 and 2015 were as follows:



	December 31,
	2016		2015
	(In millions)
Deferred tax assets:	$	—	$	—
Deferred tax liabilities:
Non-current:
Depreciation	7		9
Other	3		(1		)
Total non-current deferred tax liabilities	10		8
Accumulated deferred income taxes, net	$	10	$	8

Equity Based Compensation (Tables)

12 Months Ended

Dec. 31, 2016

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

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



	Year Ended December 31,
	2016		2015		2014
	(In millions)
Performance units	$	9	$	3	$	3
Restricted units	3		7		10
Phantom units	1		1		2
Total compensation expense	$	13	$	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.



	2016	2015			2014
Number of units granted	1,235,429	501,474			563,963
Fair value of units granted	$10.42 - $27.77	$	16.59		$	29.61
Expected price volatility	43.2% - 46.0%	27.6		%	22.2		%
Risk-free interest rate	0.86% - 0.90%	0.99		%	0.83		%
Expected life of units (in years)	3.00	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.



	2016	2015		2014
Phantom units granted	653,286	9,817		106,718
Fair value of phantom units granted	$8.12 - $15.30	$	12.70	$23.16 - $23.70

Common units, Grants in Period and Grant Date Fair Value

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



	2016		2015
Common units granted	14,914		17,384
Fair value of common units granted	$	15.35	$	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, 2016 and changes during 2016 are shown in the following table.



	Performance Units					Restricted Stock					Phantom Units
	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 12/31/2015	814,510			$	22.16	581,772			$	21.04	9,817			$	12.70
Granted⁽¹⁾	1,235,429			10.80		—			—		653,286			8.45
Vested	(6,427		)	20.77		(125,843		)	22.78		(5,594		)	12.44
Forfeited	(74,405		)	15.94		(62,934		)	19.43		(13,905		)	8.12
Units Outstanding at 12/31/2016	1,969,107			15.27		392,995			20.74		643,604			8.49
Aggregate Intrinsic Value of Units Outstanding at 12/31/2016	$	31				$	6				$	10

_____________________


(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, 2016
	Performance Units		Restricted Stock		Phantom Units
	(In millions)
Aggregate Intrinsic Value of Units Vested	$	—	$	1	$	—
Fair Value of Units Vested	—		3		—

Schedule of Unrecognized Compensation Cost, Nonvested Awards



	December 31, 2016
	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance Units	$	15	1.81
Restricted Units	2		1.12
Phantom Units	4		2.20
Total	$	21

Reportable Segments (Tables)

12 Months Ended

Dec. 31, 2016

Segment Reporting [Abstract]

Schedule of Financial Data for Business Segments and Services

Financial data for reportable segments are as follows:



Year Ended December 31, 2016	Gathering and Processing		Transportation and Storage ⁽¹⁾		Eliminations			Total
	(In millions)
Product sales	$	1,081	$	479	$	(388	)	$	1,172
Service revenue	559		545		(4		)	1,100
Total Revenues⁽²⁾	1,640		1,024		(392		)	2,272
Cost of natural gas and natural gas liquids	915		492		(390		)	1,017
Operation and maintenance, General and administrative	276		191		(2		)	465
Depreciation and amortization	212		126		—			338
Impairments	9		—		—			9
Taxes other than income tax	32		26		—			58
Operating income	$	196	$	189	$	—		$	385
Total assets	$	7,453	$	4,963	$	(1,204	)	$	11,212
Capital expenditures	$	312	$	71	$	—		$	383



Year Ended December 31, 2015	Gathering and Processing			Transportation and Storage ⁽¹⁾			Eliminations			Total
	(In millions)
Product sales	$	1,118		$	590		$	(374	)	$	1,334
Service revenue	545			542			(3		)	1,084
Total 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	$	(306	)	$	(406	)	$	—		$	(712	)
Total assets	$	7,536		$	4,976		$	(1,286	)	$	11,226
Capital expenditures	$	839		$	110		$	—		$	949



Year Ended December 31, 2014	Gathering and Processing		Transportation and Storage⁽¹⁾		Eliminations			Total
	(In millions)
Product sales	$	1,907	$	1,009	$	(616	)	$	2,300
Service revenue	517		568		(18		)	1,067
Total 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

_____________________


(1)	Equity in earnings of equity method affiliate is included in Other Income (Expense) on the Consolidated Statements of Income, and is not included in the table above. 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, 2016, 2015 and 2014.


(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, 2016

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

Summarized unaudited quarterly financial data for 2016 and 2015 are as follows:



	Quarters Ended
	March 31, 2016		June 30, 2016		September 30, 2016			December 31, 2016
	(in millions, except per unit data)
Total Revenues	$	509	$	529	$	620		$	614
Cost of natural gas and natural gas liquids	195		254		268			300
Operating income	103		57		139			86
Net income	86		39		119			69
Net income attributable to limited partners	86		39		119			68
Net income attributable to common and subordinated units	86		35		110			59

Basic earnings per unit
Common units	$	0.21	$	0.08	$	0.26		$	0.14
Subordinated units	$	0.20	$	0.08	$	0.26		$	0.14
Diluted earnings per unit
Common units	$	0.19	$	0.08	$	0.26		$	0.14
Subordinated units	$	0.20	$	0.08	$	0.26		$	0.14

	Quarters Ended
	March 31, 2015		June 30, 2015		September 30, 2015			December 31, 2015
	(in millions, except per unit data)
Total 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 limited partners	91		77		(985		)	65
Net income (loss) attributable to common and subordinated units	91		77		(985		)	65

Basic earnings (loss) per unit
Common Units	$	0.22	$	0.18	$	(2.33	)	$	0.15
Subordinated units	$	0.21	$	0.18	$	(2.34	)	$	0.15
Diluted earnings (loss) per unit
Common Units	$	0.22	$	0.18	$	(2.33	)	$	0.15
Subordinated units	$	0.21	$	0.18	$	(2.34	)	$	0.15

_____________________

(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)

3 Months Ended

5 Months Ended

12 Months Ended

13 Months Ended

Jun. 22, 2016

Jun. 21, 2016

Feb. 18, 2016

Apr. 16, 2014

USD ($)

$ / shares

Mar. 25, 2014

Dec. 31, 2016

USD ($)

board_member

Sep. 30, 2016

USD ($)

Jun. 30, 2016

USD ($)

Mar. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Sep. 30, 2015

USD ($)

Jun. 30, 2015

USD ($)

Mar. 31, 2015

USD ($)

Sep. 30, 2014

May 29, 2014

Dec. 31, 2016

USD ($)

board_member

segment

Dec. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Jun. 29, 2015

Number of reportable segments | segment

Number of representatives designated by each of CenterPoint Energy and OGE Energy | board_member

Number of independent board members | board_member

Minimum percentage of vote required by all unitholders

75.00%

Deferred revenues

$ 34,000,000

$ 30,000,000

$ 34,000,000

$ 30,000,000

Revenues

614,000,000

$ 620,000,000

$ 529,000,000

$ 509,000,000

566,000,000

$ 646,000,000

$ 590,000,000

$ 616,000,000

2,272,000,000

^[1]

2,418,000,000

^[1]

$ 3,367,000,000

^[1]

Environmental exit costs

Cash and cash equivalents

6,000,000

4,000,000

6,000,000

4,000,000

Restricted cash

17,000,000

Allowance for doubtful accounts receivable

3,000,000

Regulatory liabilities

$ 19,000,000

$ 18,000,000

19,000,000

18,000,000

AFUDC, capitalized interest

$ 4,000,000

10,000,000

8,000,000

Conversion ratio

1.279082616

Limited partners' capital account, required quarterly distribution period

60 days

45 days

60 days

Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units

Issuance of Series A Preferred Units (in units) | shares

14,520,000

Materials and Supplies

Write down of materials and supplies inventory

$ 1,000,000

9,000,000

Natural gas

Write down of materials and supplies inventory

$ 3,000,000

$ 13,000,000

$ 4,000,000

SESH

Limited partner ownership percentage interest, exercisable as early as May 2014

50.00%

49.90%

24.95%

Volume of natural gas liquids | Customer Concentration Risk

Concentration risk percentage

22.00%

18.00%

21.00%

Total revenue | Customer Concentration Risk

Concentration risk percentage

6.00%

4.00%

7.00%

Revenues

$ 129,000,000

$ 108,000,000

$ 235,000,000

Common Units | IPO

Common units issued during period (in shares) | shares

25,000,000

Initial public offering price (in dollars per share) | $ / shares

$ 20.00

Net proceeds from sale of common units, net of underwriting discounts, commissions, and other related expenses

$ 464,000,000

Period of demand fees for expiring transportation and storage contracts

3 years

Common Units | Over-Allotment Option

Common units issued during period (in shares) | shares

3,750,000

CenterPoint

Percentage share of incentive distribution rights

40.00%

CenterPoint | Common Units

54.10%

CenterPoint | Common Units | IPO

94,151,707

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

139,704,916

CenterPoint | Subordinated Units

139,704,916

OGE Energy

Percentage share of management rights

50.00%

Percentage share of incentive distribution rights

60.00%

OGE Energy | Common Units

25.70%

OGE Energy | Common Units | IPO

42,832,291

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

68,150,514

OGE Energy | Subordinated Units

68,150,514

Atoka

Limited Partner | CenterPoint

50.00%

Percentage share of management rights

50.00%

Limited Partner | CenterPoint | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units

Preferred units outstanding (in units) | shares

14,520,000

[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, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Materials and supplies	$ 30	$ 34
Natural gas and natural gas liquids inventories	11	19
Total	$ 41	$ 53

New Accounting Pronouncements - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Accounting Changes and Error Corrections [Abstract]
Restricted cash	$ 17	$ 0

Acquisition - Schedule of Assets and Liabilities Assumed (Details) hp in Thousands, $ in Millions		12 Months Ended
	May 01, 2015 USD ($) mi hp	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Purchase price allocation (in millions):
Goodwill		$ 0	$ 0	$ 1,068
Customer Relationships
Purchase price allocation (in millions):
Weighted average useful life		15 years
Monarch Natural Gas, LLC
Business Acquisition [Line Items]
Aggregate purchase price	$ 80
Purchase price allocation (in millions):
Property, plant and equipment	51
Other intangible assets	10
Goodwill	19
Total	$ 80
Monarch Natural Gas, LLC \| General and Administrative Expense
Purchase price allocation (in millions):
Acquisition costs associated with the transaction (less than $1 million)			$ 1
Monarch Natural Gas, LLC \| Customer Relationships
Purchase price allocation (in millions):
Weighted average useful life	15 years
Monarch Natural Gas, LLC \| Gathering Pipeline
Business Acquisition [Line Items]
Length of gathering pipeline (miles) \| mi	106
Monarch Natural Gas, LLC \| Gas Gathering and Processing Equipment
Business Acquisition [Line Items]
Compression horsepower \| hp	5

Earnings Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income (loss)	$ 69	$ 119	$ 39	$ 86	$ 52	$ (991)	$ 77	$ 91	$ 313	$ (771)	$ 533
Net income (loss) attributable to noncontrolling interest									1	(19)	3
Series A Preferred Unit distribution									22	0	0
General partner interest in net income									0	0	0
Net Income (Loss) Attributable to Common and Subordinated Units (Note 4)	$ 59	$ 110	$ 35	$ 86	$ 65	$ (985)	$ 77	$ 91	290	(752)	530
Dilutive effect of Series A Preferred Unit distribution									0	0	0
Dilutive effect of performance units									0	0	0
Diluted net income (loss)									$ 290	$ (752)	$ 530
Basic weighted average number of outstanding
Basic weighted average number of outstanding									424	422	412
Basic earnings (loss) per unit
Dilutive effect of Series A Preferred Units (in units)									0	0	0
Dilutive effect of performance units (in units)									0	0	0
Diluted weighted average number of outstanding units									424	422	412
Common Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss) Attributable to Common and Subordinated Units (Note 4)									$ 148	$ (381)	$ 339
Diluted net income (loss)									$ 148	$ (381)	$ 339
Basic weighted average number of outstanding
Basic weighted average number of outstanding									216	214	264
Basic earnings (loss) per unit
Basic earnings (loss) per unit	$ 0.14	$ 0.26	$ 0.08	$ 0.21	$ 0.15	$ (2.33)	$ 0.18	$ 0.22	$ 0.69	$ (1.78)	$ 1.29
Diluted weighted average number of outstanding units									216	214	264
Diluted earnings (loss) per unit	0.14	0.26	0.08	0.19	0.15	(2.33)	0.18	0.22	$ 0.69	$ (1.78)	$ 1.29
Subordinated Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss) Attributable to Common and Subordinated Units (Note 4)									$ 142	$ (371)	$ 191
Diluted net income (loss)									$ 142	$ (371)	$ 191
Basic weighted average number of outstanding
Basic weighted average number of outstanding									208	208	148
Basic earnings (loss) per unit
Basic earnings (loss) per unit	0.14	0.26	0.08	0.20	0.15	(2.34)	0.18	0.21	$ 0.68	$ (1.78)	$ 1.28
Diluted weighted average number of outstanding units									208	208	148
Diluted earnings (loss) per unit	$ 0.14	$ 0.26	$ 0.08	$ 0.20	$ 0.15	$ (2.34)	$ 0.18	$ 0.21	$ 0.68	$ (1.78)	$ 1.28
Performance Units, Restricted Units, and Phantom Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Dilutive effect of unit-based awards (in dollars per unit) (less than $.01)									$ 0.01	$ 0.01	$ 0.01

Enable Midstream Partners, LP Partners' Equity - Schedule of Cash Distributions (Details) - USD ($)

Feb. 28, 2017

Feb. 21, 2017

Feb. 15, 2017

Feb. 10, 2017

Nov. 22, 2016

Nov. 14, 2016

Nov. 01, 2016

Aug. 23, 2016

Aug. 16, 2016

Aug. 12, 2016

Aug. 02, 2016

May 13, 2016

May 06, 2016

Feb. 12, 2016

Feb. 02, 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. 04, 2014

^[1]

Distribution Made to Limited Partner [Line Items]

Nov. 14, 2016

Aug. 16, 2016

May 06, 2016

Feb. 02, 2016

Nov. 03, 2015

Aug. 03, 2015

May 05, 2015

Feb. 04, 2015

Nov. 04, 2014

Aug. 04, 2014

Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Preferred Units

Nov. 22, 2016

Aug. 23, 2016

May 13, 2016

Feb. 12, 2016

Nov. 13, 2015

Aug. 13, 2015

May 15, 2015

Feb. 13, 2015

Nov. 14, 2014

Aug. 14, 2014

Distribution Made to Limited Partner [Line Items]

Nov. 01, 2016

Aug. 02, 2016

May 06, 2016

^[2]

Distribution Made to Limited Partner [Line Items]

Nov. 14, 2016

Aug. 12, 2016

May 13, 2016

^[2]

Cash Distribution

$ 0.31800

$ 0.318

$ 0.316

$ 0.3125

$ 0.30875

$ 0.3025

$ 0.2464

Cash Distribution | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Preferred Units

$ 134,000,000

$ 132,000,000

$ 130,000,000

$ 128,000,000

$ 104,000,000

Distribution Made to Limited Partner [Line Items]

$ 0.625

$ 0.2917

^[2]

Full quarter equivalent distribution declared (in dollars per unit)

$ 9,000,000

$ 4,000,000

^[2]

$ 0.625

Annualized distribution declared (in dollars per unit)

$ 2.50

Subsequent Event | Cash Distribution

Distribution Made to Limited Partner [Line Items]

Common unit cash distribution declared (in dollars per unit)

$ 0.318

Subsequent Event | Cash Distribution | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Preferred Units

Distribution Made to Limited Partner [Line Items]

Common unit cash distribution declared (in dollars per unit)

$ 0.625

Subsequent Event | Scenario, Forecast

Distribution Made to Limited Partner [Line Items]

^[3]

Feb. 21, 2017

Subsequent Event | Scenario, Forecast | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Preferred Units

^[3]

Feb. 28, 2017

Distribution Made to Limited Partner [Line Items]

^[4]

Feb. 10, 2017

Subsequent Event | Scenario, Forecast | Cash Distribution

^[4]

Feb. 15, 2017

Distribution Made to Limited Partner [Line Items]

^[3]

$ 0.318

Subsequent Event | Scenario, Forecast | Cash Distribution | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Preferred Units

^[3]

$ 137,000,000

Distribution Made to Limited Partner [Line Items]

^[4]

$ 0.625

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

^[4]

$ 9,000,000

[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 IPO, April 16, 2014 through June 30, 2014.
[2]	The prorated quarterly distribution for the Series A Preferred Units is for a partial period beginning on February 18, 2016, and ending on March 31, 2016, which equates to $0.625 per unit on a full-quarter basis or $2.50 per unit on an annualized basis.
[3]	The board of directors of Enable GP declared this $0.318 per common unit cash distribution on February 10, 2017, to be paid on February 28, 2017, to common and subordinated unitholders of record at the close of business on February 21, 2017.
[4]	The board of directors of Enable GP declared this $0.625 per Series A Preferred Unit cash distribution on February 10, 2017, which was paid on February 15, 2017 to Series A Preferred unitholders of record at the close of business on February 10, 2017.

Enable Midstream Partners, LP Partners' Equity - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions								12 Months Ended
	Nov. 29, 2016	Jun. 22, 2016	Jun. 21, 2016	Feb. 18, 2016	Aug. 14, 2014	May 14, 2014	Feb. 14, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, required quarterly distribution period		60 days	45 days					60 days
Distributions to unitholders in accordance with First Amended and Restated Agreement of the Limited Partnership					$ 22	$ 155	$ 114
Limited partners capital account, minimum quarterly distribution, annualized								150.00%
Proceeds from issuance of Series A Preferred Units, net of issuance costs								$ 362	$ 0	$ 0
Number of common units in public offering	75,719
Limited Partner \| CenterPoint
Distribution Made to Limited Partner [Line Items]
Amount notes redeemed payable to wholly-owned subsidiary of CenterPoint Energy				$ 363
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units
Distribution Made to Limited Partner [Line Items]
Issuance of Series A Preferred Units (in units)				14,520,000
Annual percentage rate				10.00%
Liquidation preference (in dollars per share)				$ 25.00
Duration of cash distributions				5 years
Redemption price (in dollars per share)				$ 25.50
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units \| LIBOR
Distribution Made to Limited Partner [Line Items]
Annual percentage rate				8.50%
Private Placement \| Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units
Distribution Made to Limited Partner [Line Items]
Issuance of Series A Preferred Units (in units)				14,520,000
Cash purchase price (in dollars per unit)				$ 25.00
Proceeds from issuance of Series A Preferred Units, net of issuance costs				$ 362
Expenses related to offering				$ 1
Public Offering
Distribution Made to Limited Partner [Line Items]
Number of common units in public offering	10,000,000
Public offering price (in dollars per share)	$ 14.00
Proceeds received (net of underwriting discounts, structuring fees, and offering expenses)	$ 137
Over-Allotment Option
Distribution Made to Limited Partner [Line Items]
Number of common units in public offering	1,500,000
Over-Allotment Option \| Affiliate of ArcLight Capital Partners, LLC
Distribution Made to Limited Partner [Line Items]
Number of common units in public offering	1,424,281
Distribution Subordination Period 1
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, minimum annualized quarterly distribution (in dollars per unit)								$ 1.15
Distribution Subordination Period 2
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, maximum annualized quarterly distribution (in dollars per unit)								$ 1.725
Maximum
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, incentive distribution rights, percentage								50.00%
Minimum
Distribution Made to Limited Partner [Line Items]
Incentive distribution, distribution (in dollars per unit)								$ 0.330625

Property, Plant and Equipment - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 11,567	$ 11,293
Accumulated depreciation	1,424	1,162
Property, plant and equipment, net	10,143	10,131
Depreciation expense	$ 311	291	$ 249
Gathering and Processing
Property, Plant and Equipment [Line Items]
Weighted Average Useful Lives (Years)	37 years
Property, plant and equipment, gross	$ 6,987	6,478
Accumulated depreciation	$ 681	510
Transportation and Storage
Property, Plant and Equipment [Line Items]
Weighted Average Useful Lives (Years)	36 years
Property, plant and equipment, gross	$ 4,498	4,444
Accumulated depreciation	743	652
Construction work-in-progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 82	$ 371

Intangible Assets, Net - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Finite-Lived Intangible Assets [Line Items]
Amortization expense	$ 27	$ 27	$ 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
Expected amortization of intangible assets, 2021	27
Customer Relationships
Finite-Lived Intangible Assets [Line Items]
Total intangible assets	405	405
Accumulated amortization	99	72
Net intangible assets	$ 306	$ 333
Weighted average useful life	15 years

Goodwill - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
Goodwill - Narrative (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2013
Goodwill [Line Items]
Goodwill recognized		$ 1,068	$ 0
Goodwill [Roll Forward]
Goodwill		1,068
Acquisition of Monarch		19
Goodwill impairment	$ (1,087)	(1,087)
Goodwill		0
Gathering and Processing
Goodwill [Line Items]
Goodwill recognized		489	0
Goodwill [Roll Forward]
Goodwill		489
Acquisition of Monarch		19
Goodwill impairment		(508)
Goodwill		0
Transportation and Storage
Goodwill [Line Items]
Goodwill recognized		579	$ 0
Goodwill [Roll Forward]
Goodwill		579
Acquisition of Monarch		0
Goodwill impairment		(579)
Goodwill		$ 0
Enogex
Goodwill [Line Items]
Goodwill recognized				$ 438

Investment in Equity Method Affiliate - Narrative (Details) - USD ($)								1 Months Ended	3 Months Ended	5 Months Ended	12 Months Ended			13 Months Ended
	Jun. 12, 2015	Aug. 14, 2014	Jul. 25, 2014	Jun. 13, 2014	May 30, 2014	May 14, 2014	Feb. 14, 2014	Aug. 31, 2014	Sep. 30, 2014	May 29, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jun. 29, 2015	Jun. 30, 2015
Schedule of Equity Method Investments [Line Items]
Distribution to limited partner		$ 22,000,000				$ 155,000,000	$ 114,000,000
SESH
Schedule of Equity Method Investments [Line Items]
Limited partner ownership percentage interest, exercisable as early as May 2014									24.95%	24.95%
Interest contributed to the Partnership					24.95%
Limited partner units that may be issued, exercised					6,322,457
Limited partner interests in the Partnership, fair value					$ 161,000,000
Limited partner ownership percentage interest											50.00%			49.90%
Distributions from unconsolidated affiliates			$ 7,000,000								$ 28,000,000	$ 34,000,000	$ 23,000,000
SESH \| Shared Operations Service Agreements \| Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Amount billed to SESH associated with service agreements											$ 13,000,000	$ 12,000,000	13,000,000
SESH \| Investments in Equity Method Affiliates
Schedule of Equity Method Investments [Line Items]
Distributions from unconsolidated affiliates				$ 198,000,000
Investment in equity method investment													$ 187,000,000
SESH \| Investments in Equity Method Affiliates \| Senior Notes
Schedule of Equity Method Investments [Line Items]
Face amount				400,000,000
SESH \| Investments in Equity Method Affiliates \| Senior Notes \| Senior Notes Due August 2014
Schedule of Equity Method Investments [Line Items]
Face amount				$ 375,000,000
SESH \| Investments in Equity Method Affiliates \| Return of Special Distribution
Schedule of Equity Method Investments [Line Items]
Investment in equity method investment								$ 187,000,000
SESH \| Spectra Energy Partners, LP
Schedule of Equity Method Investments [Line Items]
Ownership percentage											50.00%
Percentage distributions											50.00%
SESH \| CenterPoint
Schedule of Equity Method Investments [Line Items]
Distributed ownership percentage										25.05%
Distribution to limited partner									$ 1,000,000
SESH \| CenterPoint \| Put Option
Schedule of Equity Method Investments [Line Items]
Limited partner ownership percentage interest, exercisable as early as May 2015	0.10%
Limited partner units that may be issued, exercisable as early as May 2015 (in units)															25,341
Fair value of common units	$ 1,000,000

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

12 Months Ended

Jul. 25, 2014

Jun. 13, 2014

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Balance beginning of period

$ 344

Return of investment

(15)

$ (8)

$ (198)

Equity in Earnings of Equity Method Affiliates:

Balance end of period

329

344

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

SESH

Balance beginning of period

344

Return of investment

(15)

(8)

Distributions from unconsolidated affiliates

^[1]

(43)

(42)

(23)

Balance end of period

329

344

$ 7

Distributions from Equity Method Affiliates:

SESH | Other Income (Expense)

^[1]

Income Statement Data:

Revenues

115

108

Operating income

Net income

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

Equity in Earnings of Equity Method Affiliates:

SESH | Investments in Equity Method Affiliates

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

Balance beginning of period

344

348

198

Interest acquisition of SESH

161

Additional investment in SESH

187

Contributions to equity method affiliate

Distributions from unconsolidated affiliates

^[2]

(43)

(42)

(23)

Balance end of period

329

344

348

$ 198

Equity in Earnings of Equity Method Affiliates:

Distributions from Equity Method Affiliates:

SESH | Special Distribution | Investments in Equity Method Affiliates

^[2]

$ 43

$ 42

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

Return of investment

$ (198)

[1]	Excludes $198 million in special distributions for the return of investment in SESH for the year ended December 31, 2014.
[2]	Distributions from equity method affiliate includes a $28 million, $34 million and $23 million return on investment and a $15 million, $8 million and zero return of investment for the years ended December 31, 2016, 2015 and 2014, respectively.

Investment in Equity Method Affiliate - Financial Information of SESH (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Balance Sheet Data:
Investment in SESH	$ 329	$ 344
SESH
Balance Sheet Data:
Current assets	31	45
Property, plant and equipment, net	1,110	1,127
Total assets	1,141	1,172
Current liabilities	18	18
Long-term debt	397	397
Members’ equity	726	757
Total liabilities and members’ equity	1,141	1,172
Investment in SESH	329	344
Less: Capitalized interest on investment in SESH	(1)	(1)
Add: Basis differential, net of amortization	35	36
The Partnership’s share of members’ equity	$ 363	$ 379

Debt - Schedule of Outstanding Debt (Details) - USD ($)

Dec. 31, 2016

Dec. 31, 2015

^[1]

$ 0

$ 236,000,000

Less: Unamortized debt expense

17,000,000

23,000,000

Total debt

3,003,000,000

3,282,000,000

10,000,000

12,000,000

Less: Notes payable—affiliated companies

363,000,000

Total long-term debt

2,993,000,000

2,671,000,000

Senior Notes | 2.400% Senior Notes

Senior Notes | 3.900% Senior Notes

500,000,000

Senior Notes | 5.000% Senior Notes

600,000,000

Senior Notes | 6.25% Senior Notes

550,000,000

250,000,000

18,000,000

Term Loan Agreement

Revolving Credit Facility

450,000,000

636,000,000

310,000,000

$ 0

$ 236,000,000

[1]	There were no commercial paper borrowings outstanding as of December 31, 2016. Short-term debt includes $236 million of commercial paper as of December 31, 2015.

Debt - Maturities of Long Term Debt (Details) $ in Millions	Dec. 31, 2016 USD ($)
Debt Disclosure [Abstract]
Long-term debt maturities in 2017	$ 0
Long-term debt maturities in 2018	450
Long-term debt maturities in 2019	500
Long-term debt maturities in 2020	886
Long-term debt maturities in 2021	0
Thereafter	$ 1,150

Debt - Narrative (Details)

12 Months Ended

Dec. 29, 2015

USD ($)

Oct. 09, 2015

Jul. 31, 2015

USD ($)

time

May 27, 2014

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2014

USD ($)

Dec. 31, 2015

USD ($)

Jun. 18, 2015

USD ($)

Jul. 15, 2014

USD ($)

Jan. 31, 2014

USD ($)

May 01, 2013

USD ($)

Commercial paper, authorized

$ 1,400,000,000

^[1]

$ 0

$ 236,000,000

Unamortized debt expense

10,000,000

12,000,000

17,000,000

23,000,000

Other Assets

Revolving Credit Facility

Unamortized debt expense

15,000,000

18,000,000

Maximum borrowing capacity

$ 1,750,000,000

Letters of credit principal advances

636,000,000

Letters of credit outstanding amount

$ 3,000,000

Weighted average interest rate percentage

2.21%

Unused capacity, commitment fee percentage

0.20%

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 | LIBOR

Basis spread on variable rate percentage

1.50%

Revolving Credit Facility | Minimum

Threshold for debt covenant ratio

$ 25,000,000

Revolving Credit Facility | Maximum

Consolidated debt to EBITDA ratio

5.00

Threshold for debt covenant ratio for acquisitions

5.50

Senior unsecured 2013 Term Loan Facility

Maximum borrowing capacity

$ 1,050,000,000

Term Loan Agreement

Losses on extinguishment of debt

$ 4,000,000

Enable Oklahoma Term Loan | Term Loan Agreement

Maximum borrowing capacity

$ 250,000,000

Unsecured Debt | 2015 Term Loan Facility

Weighted average interest rate percentage

1.86%

Term loan facility, term

3 years

Minimum prepayment amount

$ 450,000,000

Additional term of loan

1 year

$ 1,000,000

Amount of multiple to prepay the amount outstanding

$ 500,000

Principal amount of term loan facility

$ 450,000,000

Unsecured Debt | 2015 Term Loan Facility | LIBOR

Basis spread on variable rate percentage

1.375%

Unsecured Debt | 2015 Term Loan Facility | Maximum

Number of times option may be exercised | time

Senior Notes

Proceeds from issuance of debt

$ 1,630,000,000

Senior Notes | 2.400% Senior Notes

$ 500,000,000

2.40%

Senior Notes | 3.900% Senior Notes

2.59%

$ 600,000,000

3.90%

Senior Notes | 5.000% Senior Notes

4.02%

$ 550,000,000

5.00%

Senior Notes | 6.875% Senior Notes

5.09%

$ 200,000,000

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

6.875%

Additional interest rate percentage

Unamortized discount

$ 1,000,000

Unamortized debt expense

10,000,000

0.25%

Period for additional interest rate percentage

90 days

Amount of additional interest expense

$ 1,000,000

Senior Notes | 6.25% Senior Notes

$ 250,000,000

6.25%

3.83%

$ 18,000,000

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

$ 0

$ 236,000,000

[1]	There were no commercial paper borrowings outstanding as of December 31, 2016. Short-term debt includes $236 million of commercial paper as of December 31, 2015.

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 ($)

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 2,993,000,000

$ 2,671,000,000

^[1]

236,000,000

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

9,000,000

1,134,000,000

$ 8,000,000

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

Impairment of jurisdictional pipelines

12,000,000

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

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

236,000,000

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

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

350,000,000

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

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

^[2]

636,000,000

310,000,000

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

Significant other observable inputs (Level 2) | EOIT Senior Notes (Level 2)

450,000,000

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)

260,000,000

280,000,000

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

1,521,000,000

1,255,000,000

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

9,000,000

10,000,000

$ 7,000,000

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

Write down of intangibles

25,000,000

6,000,000

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

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

8,000,000

9,000,000

Write down of property plant and equipment

19,000,000

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

1,000,000

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

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

363,000,000

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

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

^[2]

636,000,000

310,000,000

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

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

450,000,000

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)

268,000,000

273,000,000

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

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

$ 1,649,000,000

$ 1,650,000,000

[1]	There were no commercial paper borrowings outstanding as of December 31, 2016. Short-term debt includes $236 million of commercial paper as of December 31, 2015.
[2]	Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. There was zero and $236 million of commercial paper outstanding as of December 31, 2016 and 2015, respectively.

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

Dec. 31, 2016

Dec. 31, 2015

Fuel reserves for under retained fuel due from shippers

$ 0

$ 6

Fuel reserves for over retained fuel due from shippers

Recurring Measurement | Commodity Contracts

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)

Derivative liability, netting adjustment

(3)

Recurring Measurement | Gas Imbalances

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]

Recurring Measurement | Quoted market prices in active market for identical assets (Level 1) | Commodity Contracts

^[2],[3]

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

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

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

^[1],[2]

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

^[2],[3]

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

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

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

^[1],[2]

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

^[2],[3]

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

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

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

^[1],[2]

Crude oil (for condensate) financial futures/swaps

^[2],[3]

$ 0

[1]	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of zero and $6 million at December 31, 2016 and 2015, 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, 2016 and 2015.
[3]	Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $5 million at each of December 31, 2016 and 2015, 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 - Schedule of Changes in Fair Values of Level 3 Financial Assets (Details) - Commodity Contracts - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]

Beginning Balance

$ 0

$ 5

Gains (Losses) included in earnings

Settlements

(8)

Transfers out of Level 3

(9)

^[1]

Ending Balance

Natural gas liquids financial futures/swaps

Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]

Beginning Balance

Gains (Losses) included in earnings

(13)

Settlements

(6)

Transfers out of Level 3

^[1]

Ending Balance

$ (8)

$ 4

[1]	The Partnership utilizes WTI crude oil swaps to manage exposure to condensate price risk. As the over-the-counter WTI crude oil swap is an active market, these derivative instruments were 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 - Market Approach Valuation Technique - Unobservable inputs (Level 3) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($) $ / gal
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value \| $	$ (8)
Minimum
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Forward Curve Range (Per gallon)	0.385
Maximum
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Forward Curve Range (Per gallon)	0.936

Derivative Instruments and Hedging Activities - Quantitative Disclosures Related to Derivative Instruments (Details)
bbl in Thousands, MMBTU in Millions

12 Months Ended

Dec. 31, 2016

USD ($)

MMBTU

bbl

Dec. 31, 2015

USD ($)

MMBTU

bbl

Designated cash flow hedges | $

$ 0

Fair value hedges | $

$ 0

Not Designated as Hedging Instrument | Financial fixed futures/swaps | Purchases

Not Designated as Hedging Instrument | Financial fixed futures/swaps | Sales

^[1]

Not Designated as Hedging Instrument | Financial basis futures/swaps | Purchases

^[1]

Not Designated as Hedging Instrument | Financial basis futures/swaps | Sales

^[1]

Not Designated as Hedging Instrument | Physical purchases/sales | Purchases

^[1]

Not Designated as Hedging Instrument | Physical purchases/sales | Sales

^[1]

Not Designated as Hedging Instrument | Financial futures/swaps- Crude oil (for condensate) | Purchases

^[1]

Not Designated as Hedging Instrument | Financial futures/swaps- Crude oil (for condensate) | Sales

^[2]

Not Designated as Hedging Instrument | Financial futures/swaps- Natural gas liquids | Purchases

^[2]

540

506

Not Designated as Hedging Instrument | Financial futures/swaps- Natural gas liquids | Sales

^[3]

Not Designated as Hedging Instrument | Natural gas

^[3]

1,133

1,011

Percent of contract with durations of one year or less

100.00%

97.70%

Percent of contracts with durations of more than one year and less than two years

2.30%

Not Designated as Hedging Instrument | Crude oil (for condensate)

Percent of contract with durations of one year or less

100.00%

Not Designated as Hedging Instrument | Volume of natural gas liquids

Percent of contract with durations of one year or less

100.00%

[1]	As of December 31, 2016, 100% of the natural gas contracts have durations of one year or less. As of December 31, 2015, 97.7% of the natural gas contracts had durations of one year or less and 2.3% had durations of more than one year and less than two years.
[2]	As of December 31, 2016 and 2015, 100% of the crude oil (for condensate) contracts have durations of one year or less.
[3]	As of December 31, 2016 and 2015, 100% of the natural gas liquid contracts have durations of one year or less.

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

Dec. 31, 2016

Dec. 31, 2015

^[1]

$ 2

$ 31

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

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

$ 8

$ 0

[1]	See Note 11 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheets as of December 31, 2016 and 2015.

Derivative Instruments and Hedging Activities - Amounts Recognized in Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	$ (43)	$ 39	$ 49
Change in fair value of derivatives	(60)	(8)	38
Realized gain on derivatives	17	47	11
Gain (loss) on derivative activity	(43)	39	49
Cash collateral posted	3
Natural gas \| Physical purchases/sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	(19)	26	37
Natural gas \| Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	(7)	(9)	1
Crude oil (for condensate) \| Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	(4)	12	9
Natural gas liquids financial futures/swaps \| Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	$ (13)	$ 10	$ 2

Supplemental Disclosure of Cash Flow Information - Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Interest, net of capitalized interest	$ 105	$ 85	$ 77
Income taxes, net of refunds	0	1	1
Accounts payable related to capital expenditures	18	52	93
Issuance of common units upon interest acquisition of SESH (Note 9)	$ 0	$ 1	$ 161

Supplemental Disclosure of Cash Flow Information - Schedule of Reconciliation of Cash and Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]
Cash and cash equivalents	$ 6	$ 4
Restricted cash	17	0
Cash, cash equivalents and restricted cash shown in the Consolidated Statement of Cash Flows	$ 23	$ 4	$ 12	$ 108

Related Party Transactions - Narrative (Details)			12 Months Ended
Related Party Transactions - Narrative (Details)	Dec. 06, 2016 mi	Feb. 18, 2016 USD ($) $ / shares shares	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($) mi	Dec. 31, 2014 USD ($)
Related Party Transaction [Line Items]
Remaining net book value of pipeline segment			$ 10,143,000,000	$ 10,131,000,000
Partnership's revenues from affiliated companies as a percent of total revenues			7.00%	7.00%	6.00%
Rent and maintenance expenses			$ 17,000,000
Proceeds from issuance of Series A Preferred Units, net of issuance costs			362,000,000	$ 0	$ 0
Outstanding long-term notes payable			0	363,000,000
Notes payable—affiliated companies			$ 0	$ 363,000,000
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units
Related Party Transaction [Line Items]
Issuance of Series A Preferred Units (in units) \| shares		14,520,000
Private Placement \| Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units
Related Party Transaction [Line Items]
Issuance of Series A Preferred Units (in units) \| shares		14,520,000
Cash purchase price (in dollars per unit) \| $ / shares		$ 25.00
Proceeds from issuance of Series A Preferred Units, net of issuance costs		$ 362,000,000
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 \| Minimum
Related Party Transaction [Line Items]
Period notice of termination for reimbursements for all employee costs			90 days
CenterPoint
Related Party Transaction [Line Items]
Outstanding long-term notes payable				$ 363,000,000
Notes payable—affiliated companies				363,000,000
Affiliate interest expense			$ 1,000,000	$ 8,000,000	$ 8,000,000
CenterPoint \| Certain Services and Support Functions
Related Party Transaction [Line Items]
Expense reimbursement annual caps			$ 7,000,000
OGE Energy \| Minimum
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			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			$ 6,000,000
Subsidiary of Common Parent \| 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
Subsidiary of Common Parent \| Amount Reimbursed for Costs Incurred in Connecting New Pipeline Segment \| Pipelines
Related Party Transaction [Line Items]
Amount of reimbursement				$ 7,000,000
CenterPoint \| Subsidiary of Common Parent \| Three Services included in Transportation and Storage Agreements
Related Party Transaction [Line Items]
Period of written notice prior to contract termination			180 days
CenterPoint \| Affiliate \| Lease Agreement with Affiliate of CenterPoint Energy
Related Party Transaction [Line Items]
Rent and maintenance expenses			$ 3,000,000
OGE Energy \| Subsidiary of Common Parent \| Transportation Agreement between OGE Energy and EOIT \| Pipelines
Related Party Transaction [Line Items]
Term of transportation agreement	20 years
Length of pipeline \| mi	80

Related Party Transactions - Related Party Activity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Revenues from affiliated companies	$ 159	$ 162	$ 186
Cost of goods sold from affiliate	14	17	21
Total corporate services and seconded employees expense	40	61	289
CenterPoint
Related Party Transaction [Line Items]
Cost of goods sold from affiliate	0	2	2
CenterPoint \| Gas Transportation and Storage
Related Party Transaction [Line Items]
Revenues from affiliated companies	110	110	112
CenterPoint \| Gas Sales
Related Party Transaction [Line Items]
Revenues from affiliated companies	1	7	22
CenterPoint \| Seconded Employee Costs
Related Party Transaction [Line Items]
Total corporate services and seconded employees expense	0	0	138
CenterPoint \| Corporate Services
Related Party Transaction [Line Items]
Total corporate services and seconded employees expense	6	15	29
OGE Energy
Related Party Transaction [Line Items]
Cost of goods sold from affiliate	14	15	19
OGE Energy \| Gas Transportation and Storage
Related Party Transaction [Line Items]
Revenues from affiliated companies	36	37	39
OGE Energy \| Gas Sales
Related Party Transaction [Line Items]
Revenues from affiliated companies	12	8	13
OGE Energy \| Seconded Employee Costs
Related Party Transaction [Line Items]
Total corporate services and seconded employees expense	29	35	105
OGE Energy \| Corporate Services
Related Party Transaction [Line Items]
Total corporate services and seconded employees expense	$ 5	$ 11	$ 17

Commitments and Contingencies - Operating Leases Future Minimum Payments and Other Commitments (Details) $ in Millions	Dec. 31, 2016 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Noncancellable operating leases due in 2017	$ 10
Noncancellable operating leases due in 2018	4
Noncancellable operating leases due in 2019	3
Noncancellable operating leases due in 2020	0
Noncancellable operating leases due in 2021	0
Noncancellable operating leases due after 2021	0
Total	$ 17

Commitments and Contingencies - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($) ft² agreement	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Rent expense \| $	$ 27	$ 32	$ 23
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	78
Number of compression service agreements on a month-to-month basis	40
Number of compression service agreements expiring in 2017	32
Number of compression service agreements expiring in 2018	6
Number of gas treating agreements	6

Income Taxes - Schedule of Expense (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Provision (benefit) for current income taxes
Federal	$ (1)	$ 0	$ 0
State	0	1	1
Total provision (benefit) for current income taxes	(1)	1	1
Provision (benefit) for deferred income taxes, net
Federal	3	0	0
State	(1)	(1)	1
Total provision (benefit) for deferred income taxes, net	2	(1)	1
Total income tax expense	$ 1	$ 0	$ 2

Income Taxes - Effective Tax Rate Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income (loss) before income taxes	$ 314	$ (771)	$ 535
Federal statutory rate	0.00%	0.00%	0.00%
Expected federal income tax expense	$ 0	$ 0	$ 0
State income taxes, net of federal income tax	1	0	2
Total	1	0	2
Total income tax expense	$ 1	$ 0	$ 2
Effective tax rate	0.30%	0.00%	0.40%

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Deferred tax assets	$ 0	$ 0
Deferred tax liabilities:
Depreciation	7	9
Other	3	(1)
Total non-current deferred tax liabilities	10	8
Accumulated deferred income taxes, net	$ 10	$ 8

Equity Based Compensation - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 13	$ 11	$ 15
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	9	3	3
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	3	7	10
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 1	$ 1	$ 2
Common Units \| Long Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units that may be delivered pursuant to vested awards	13,100,000

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Vesting period

3 years

Award cycle

3 years

Number of units granted (in units)

2 years

1,235,429

^[1]

501,474

563,963

Expected price volatility percentage

$ 10.80

^[1]

$ 16.59

$ 29.61

27.60%

22.20%

Risk-free interest rate percentage

0.99%

0.83%

Expected life of units (in years)

3 years

Awards Granted in 2016

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

Duration of daily stock price observations to determine expected price volatility

2 years

Average volatility period of peer group companies

1 year

Awards Granted in 2015

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

Duration of daily stock price observations to determine expected price volatility

1 year

Average volatility period of peer group companies

2 years

Awards Granted in 2014

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

Average volatility period of peer group companies

2 years

Minimum

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

Payout percentage from target level of achievement of performance goal

0.00%

Expected price volatility percentage

$ 10.42

43.20%

Risk-free interest rate percentage

0.86%

Maximum

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

Payout percentage from target level of achievement of performance goal

200.00%

Expected price volatility percentage

$ 27.77

46.00%

Risk-free interest rate percentage

0.90%

[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

1 Months Ended

12 Months Ended

Apr. 30, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Restricted units

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

^[1]

Restricted units | Certain Partnership Employees

^[1]

$ 0.00

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

279,677

304,901

Restricted units | Certain Partnership Employees | Minimum

2 years

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

Restricted units | Certain Partnership Employees | Maximum

$ 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

Phantom units

653,286

^[1]

9,817

106,718

2 years

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

^[1]

$ 8.45

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

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

$ 12.70

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

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

8.12

$ 23.16

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

Phantom units | Certain Partnership Employees

$ 15.30

$ 23.70

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

Phantom units | Independent Directors Of Enable GP

653,286

9,817

100,000

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

Other Awards | Independent Directors Of Enable GP

6,718

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

14,914

17,384

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

$ 15.35

$ 11.12

[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) - $ / shares

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Performance units

2 years

1,235,429

^[1]

501,474

563,963

Vesting period

3 years

Performance units | Minimum

$ 10.80

^[1]

$ 16.59

$ 29.61

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

0.00%

Performance units | Maximum

$ 10.42

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

200.00%

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

$ 27.77

Restricted units

^[1]

Restricted units | Executive Officer

^[1]

$ 0.00

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

687,500

Restricted units | Chief Executive Officer

$ 0.00

$ 22.60

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

Percentage forfeited upon departure

50.00%

Restricted units | Chief Financial Officer

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

Vesting period

4 years

Restricted units | Certain Partnership Employees

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

2 years

Restricted units | Certain Partnership Employees | Minimum

279,677

304,901

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

Restricted units | Certain Partnership Employees | Maximum

$ 16.75

$ 23.56

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

Restricted units | Percentage Based Vesting | Chief Executive Officer

$ 19.18

$ 25.50

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

Restricted units | Percentage Based Vesting | Chief Financial Officer

375,000

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

Restricted units | Vesting on August 1, 2014 | Chief Executive Officer

137,500

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

Restricted units | Vesting on February 1, 2015 | Chief Executive Officer

40.00%

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

Restricted units | Vesting on July 15, 2015 | Chief Executive Officer

20.00%

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

Restricted units | Vesting on May 29, 2015 | Chief Executive Officer

40.00%

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

Restricted units | Equal Annual Based Vesting | Chief Executive Officer

50.00%

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

Restricted units | Equal Annual Based Vesting | Chief Financial Officer

150,000

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

Restricted units | Vesting on March 1, 2015 | Chief Financial Officer

25,000

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

Restricted units | Vesting on March 1, 2016 | Chief Financial Officer

45.46%

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

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

54.54%

[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, 2016

Dec. 31, 2015

Dec. 31, 2014

Performance units

Units Outstanding at 12/31/2015 (in units)

814,510

Units Outstanding at 12/31/2016 (in units)

1,235,429

^[1]

501,474

563,963

Vested (in units)

(6,427)

Forfeited (in units)

(74,405)

1,969,107

814,510

Weighted Average Grant-Date Fair Value, Per Unit

Units Outstanding at 12/31/2015 (in dollars per share)

$ 22.16

Vested (in dollars per share)

10.80

^[1]

$ 16.59

$ 29.61

20.77

Forfeited (in dollars per share)

15.94

Units Outstanding at 12/31/2016 (in dollars per share)

$ 15.27

$ 22.16

Aggregate Intrinsic Value of Units Outstanding at 12/31/2016

$ 31

Aggregate Intrinsic Value of Units Vested

Fair Value of Units Vested

$ 0

Performance units | Minimum

Weighted Average Grant-Date Fair Value, Per Unit

Payout percentage from target level of achievement of performance goal

$ 10.42

0.00%

Performance units | Maximum

Weighted Average Grant-Date Fair Value, Per Unit

Payout percentage from target level of achievement of performance goal

$ 27.77

200.00%

Restricted units

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

Units Outstanding at 12/31/2015 (in units)

581,772

Units Outstanding at 12/31/2016 (in units)

^[1]

Vested (in units)

(125,843)

Forfeited (in units)

(62,934)

392,995

581,772

Weighted Average Grant-Date Fair Value, Per Unit

Units Outstanding at 12/31/2015 (in dollars per share)

$ 21.04

Vested (in dollars per share)

^[1]

0.00

22.78

Forfeited (in dollars per share)

19.43

Units Outstanding at 12/31/2016 (in dollars per share)

$ 20.74

$ 21.04

Aggregate Intrinsic Value of Units Outstanding at 12/31/2016

$ 6

Aggregate Intrinsic Value of Units Vested

Fair Value of Units Vested

$ 3

Phantom units

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

Units Outstanding at 12/31/2015 (in units)

9,817

Units Outstanding at 12/31/2016 (in units)

653,286

^[1]

9,817

106,718

Vested (in units)

(5,594)

Forfeited (in units)

(13,905)

643,604

9,817

Weighted Average Grant-Date Fair Value, Per Unit

Units Outstanding at 12/31/2015 (in dollars per share)

$ 12.70

Vested (in dollars per share)

^[1]

8.45

12.44

Forfeited (in dollars per share)

8.12

Units Outstanding at 12/31/2016 (in dollars per share)

$ 8.49

$ 12.70

Aggregate Intrinsic Value of Units Outstanding at 12/31/2016

$ 10

Aggregate Intrinsic Value of Units Vested

Fair Value of Units Vested

$ 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, 2016 USD ($) shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 21
Long Term Incentive Plan \| Common Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for issuance \| shares	9,307,350
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 15
Weighted Average to be Recognized (In years)	1 year 9 months 22 days
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 2
Weighted Average to be Recognized (In years)	1 year 1 month 13 days
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 4
Weighted Average to be Recognized (In years)	2 years 2 months 12 days

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

3 Months Ended

12 Months Ended

Dec. 31, 2016

USD ($)

Sep. 30, 2016

USD ($)

Jun. 30, 2016

USD ($)

Mar. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Sep. 30, 2015

USD ($)

Jun. 30, 2015

USD ($)

Mar. 31, 2015

USD ($)

Dec. 31, 2016

USD ($)

segment

Dec. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Number of reportable segments | segment

$ 1,172

$ 1,334

$ 2,300

1,100

1,084

1,067

$ 614

$ 620

$ 529

$ 509

$ 566

$ 646

$ 590

$ 616

2,272

^[1]

2,418

^[1]

3,367

^[1]

Operation and maintenance, General and administrative

300

268

254

195

241

287

277

292

1,017

1,097

1,914

465

522

527

338

318

276

1,134

$ 139

$ 57

$ 103

^[2]

$ (975)

^[2]

$ 93

^[2]

$ 104

^[2]

385

(712)

586

11,212

11,226

11,212

11,226

11,837

949

Operating Segments | Gathering and Processing

383

869

837

1,081

1,118

1,907

559

545

517

^[1]

1,640

1,663

2,424

Operation and maintenance, General and administrative

915

908

1,585

276

293

297

212

195

160

543

196

(306)

349

7,453

7,536

7,453

7,536

8,356

839

Operating Segments | Transportation and Storage

312

740

^[3]

479

590

1,009

^[3]

545

542

568

^[1],[3]

1,024

1,132

1,577

Operation and maintenance, General and administrative

^[3]

492

565

961

^[3]

191

230

232

^[3]

126

123

116

^[3]

591

^[3]

^[3]

189

(406)

237

^[3]

4,963

4,976

4,963

4,976

5,493

^[3]

110

^[3]

103

Eliminations

(388)

(374)

(616)

(4)

(3)

(18)

^[1]

(392)

(377)

(634)

Operation and maintenance, General and administrative

(390)

(376)

(632)

(2)

(1)

(2)

$ (1,204)

$ (1,286)

(1,204)

(1,286)

(2,012)

$ 0

Effect of Fourth Quarter Events [Line Items]

$ 0

$ (6)

[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]	Equity in earnings of equity method affiliate is included in Other Income (Expense) on the Consolidated Statements of Income, and is not included in the table above. 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, 2016, 2015 and 2014.

Quarterly Financial Data (Unaudited) - Narrative (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 614

$ 620

$ 529

$ 509

$ 566

$ 646

$ 590

$ 616

$ 2,272

^[1]

$ 2,418

^[1]

$ 3,367

^[1]