Edgar Filing: Enable Midstream Partners, LP

Large accelerated filer

Accelerated filer

Non-accelerated filer

þ (Do not check if a smaller reporting company)

Smaller reporting company

Q3 2014 ENBL 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

_______________________________________

FORM 10-Q

_______________________________________

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES AND EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2014

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission File No. 1-36413

_______________________________________

ENABLE MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)

_______________________________________



Delaware		72-1252419
(State or jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

One Leadership Square

211 North Robinson Avenue

Suite 950

Oklahoma City, Oklahoma 73102

(Address of principal executive offices)

(Zip Code)

Registrant's telephone number, including area code: (405) 525-7788

_______________________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þ Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes þ No

At October 17, 2014, there were 214,355,023 common units and 207,855,430 subordinated units outstanding.

Table of Contents

ENABLE MIDSTREAM PARTNERS, LP

FORM 10-Q

TABLE OF CONTENTS



	Page
GLOSSARY OF TERMS	1
FORWARD-LOOKING STATEMENTS	3

Part I - FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Condensed Combined and Consolidated Statements of Income	4
Condensed Combined and Consolidated Statements of Comprehensive Income	5
Condensed Consolidated Balance Sheets	6
Condensed Combined and Consolidated Statements of Cash Flows	7
Condensed Combined and Consolidated Statements of Enable Midstream Partners, LP Parent Net Equity and Partners' Capital	9
Notes to Condensed Combined and Consolidated Financial Statements	10
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3. Quantitative and Qualitative Disclosures About Market Risk	45
Item 4. Controls and Procedures	46

Part II - OTHER INFORMATION
Item 1. Legal Proceedings	46
Item 1A. Risk Factors	47
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 6. Exhibits	47

Signature	0

Table of Contents

GLOSSARY



Adjusted EBITDA.	Net income from continuing operations before interest expense, income tax expense, depreciation and amortization expense and certain other items management believes affect the comparability of operating results.
ArcLight.	ArcLight Capital Partners, LLC, a Delaware limited liability company, its affiliated entities ArcLight Energy Partners Fund V, L.P., ArcLight Energy Partners Fund IV, L.P., Bronco Midstream Partners, L.P., Bronco Midstream Infrastructure LLC and Enogex Holdings LLC, and their respective general partners and subsidiaries.
ASU.	Accounting Standards Update.
Barrel.	42 U.S. gallons of petroleum products.
Bbl.	Barrel.
Bcf/d.	Billion cubic feet per day.
Btu.	British thermal unit. When used in terms of volume, Btu refers to the amount of natural gas required to raise the temperature of one pound of water by one degree Fahrenheit at one atmospheric pressure.
CenterPoint Energy.	CenterPoint Energy, Inc., a Texas corporation, and its subsidiaries, other than Enable Midstream Partners, LP.
Condensate.	A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
EGT.	Enable Gas Transmission, LLC, a wholly owned subsidiary of the Partnership that operates a 5,987-mile interstate pipeline that provides natural gas transportation and storage services to customers principally in the Anadarko, Arkoma and Ark-La-Tex basins in Oklahoma, Texas, Arkansas, Louisiana and Kansas.
Enable GP.	Enable GP, LLC, a Delaware limited liability company and the general partner of Enable Midstream Partners, LP.
Enable Midstream Services.	Enable Midstream Services, LLC, a wholly owned subsidiary of Enable Midstream Partners, LP.
Enable Oklahoma.	Enable Oklahoma Intrastate Transmission, LLC, formerly Enogex LLC, a wholly owned subsidiary of the Partnership that operates a 2,242-mile intrastate pipeline that provides natural gas transportation and storage services to customers in Oklahoma.
Enogex.	Enogex LLC, a Delaware limited liability company.
Exchange Act.	Securities Exchange Act of 1934, as amended.
FASB.	Financial Accounting Standards Board.
FERC.	Federal Energy Regulatory Commission.
Fractionation.	The separation of the heterogeneous mixture of extracted NGLs into individual components for end-use sale.
GAAP.	Generally accepted accounting principles in the United States.
Gas imbalance.	The difference between the actual amounts of natural gas delivered from or received by a pipeline, as compared to the amounts scheduled to be delivered or received.
Gross margin.	Total revenues minus cost of goods sold, excluding depreciation and amortization.
LIBOR.	London Interbank Offered Rate.
MBbl/d.	Thousand barrels per day.
MFA.	Master Formation Agreement dated March 14, 2013.
MRT.	Enable Mississippi River Transmission, LLC, a wholly owned subsidiary of the Partnership that operates a 1,663-mile interstate pipeline that provides natural gas transportation and storage services principally in Texas, Arkansas, Louisiana, Missouri and Illinois.
NGLs.	Natural gas liquids, which are the hydrocarbon liquids contained within natural gas including condensate.
NYMEX.	New York Mercantile Exchange.
Offering.	Initial public offering of Enable Midstream Partners, LP.
OGE Energy.	OGE Energy Corp., an Oklahoma corporation, and its subsidiaries, other than Enable Midstream Partners, LP.
Partnership.	Enable Midstream Partners, LP.

Table of Contents



Prospectus.	The prospectus related to the Offering dated April 10, 2014 as filed with the Securities and Exchange Commission on April 11, 2014.
SEC.	Securities and Exchange Commission.
Securities Act.	Securities Act of 1933, as amended.
SESH.	Southeast Supply Header, LLC, in which the Partnership owns a 49.90% interest at September 30, 2014, that operates a 286-mile interstate natural gas pipeline from Perryville, Louisiana, to southeastern Alabama near the Gulf Coast.
TBtu.	Trillion British thermal units.
TBtu/d.	Trillion British thermal units per day.
Term Loan Facility.	$1.05 billion senior unsecured term loan facility.
WTI.	West Texas Intermediate.
2019 Notes.	$500 million 2.400% senior notes due 2019.
2024 Notes.	$600 million 3.900% senior notes due 2024.
2044 Notes.	$550 million 5.000% senior notes due 2044.

Table of Contents

FORWARD-LOOKING STATEMENTS

Some of the information in this report may contain forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “could,” “will,” “should,” “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this report include our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance, including revenue projections, capital expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this report and in the Prospectus. Those risk factors and other factors noted throughout this report and in the Prospectus could cause our actual results to differ materially from those disclosed in any forward-looking statement. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:


•	changes in general economic conditions;


•	competitive conditions in our industry;


•	actions taken by our customers and competitors;


•	the demand for natural gas, NGLs, crude oil and midstream services;


•	our ability to successfully implement our business plan;


•	our ability to complete internal growth projects on time and on budget;


•	the price and availability of debt and equity financing;


•	operating hazards and other risks incidental to transporting, storing and gathering natural gas, NGLs, crude oil and midstream products;


•	natural disasters, weather-related delays, casualty losses and other matters beyond our control;


•	interest rates;


•	labor relations;


•	large customer defaults;


•	changes in the availability and cost of capital;


•	changes in tax status;


•	the effects of existing and future laws and governmental regulations;


•	changes in insurance markets impacting costs and the level and types of coverage available;


•	the timing and extent of changes in commodity prices;


•	the suspension, reduction or termination of our customers’ obligations under our commercial agreements;


•	disruptions due to equipment interruption or failure at our facilities, or third-party facilities on which our business is dependent;


•	the effects of future litigation; and


•	other factors set forth in this report and our other filings with the SEC, including the Prospectus.

Forward-looking statements speak only as of the date on which they are made. We expressly disclaim any obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by law.

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED COMBINED AND CONSOLIDATED STATEMENTS OF INCOME

(unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In millions, except per unit data)
Revenues (including revenues from affiliates (Note 11))	$	803		$	792		$	2,632		$	1,665
Cost of Goods Sold, excluding depreciation and amortization (including expenses from affiliates (Note 11))	439			459			1,550			827
Operating Expenses:
Operation and maintenance (including expenses from affiliates (Note 11))	128			124			383			302
Depreciation and amortization	69			67			205			148
Impairment	1			12			1			12
Taxes other than income taxes	14			15			41			37
Total Operating Expenses	212			218			630			499
Operating Income	152			115			452			339
Other Income (Expense):
Interest expense (including expenses from affiliates (Note 11))	(20		)	(13		)	(50		)	(53		)
Equity in earnings of equity method affiliates	5			3			12			12
Interest income—affiliated companies	—			1			—			9
Other, net	3			—			(2		)	—
Total Other Income (Expense)	(12		)	(9		)	(40		)	(32		)
Income Before Income Taxes	140			106			412			307
Income tax expense (benefit)	1			1			2			(1,195		)
Net Income	$	139		$	105		$	410		$	1,502
Less: Net income attributable to noncontrolling interest	—			1			2			2
Net Income attributable to Enable Midstream Partners, LP	$	139		$	104		$	408		$	1,500
Limited partners' interest in net income attributable to Enable Midstream Partners, LP (Note 4)	$	139		104			$	408		174
Basic and diluted earnings per common limited partner unit (Note 4)	$	0.33		$	0.27		$	1.00		$	0.45
Basic and diluted earnings per subordinated limited partner unit (Note 4)	$	0.33		$	—		$	0.98		$	—

See Notes to the Unaudited Condensed Combined and Consolidated Financial Statements

Table of Contents

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED COMBINED AND CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(In millions)
Net income	$	139	$	105	$	410	$	1,502
Comprehensive income	139		105		410		1,502
Less: Comprehensive income attributable to noncontrolling interest	—		1		2		2
Comprehensive income attributable to Enable Midstream Partners, LP	$	139	$	104	$	408	$	1,500

See Notes to the Unaudited Condensed Combined and Consolidated Financial Statements

Table of Contents

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2014		December 31, 2013
	(In millions)
Current Assets:
Cash and cash equivalents	$	18	$	108
Accounts receivable	318		306
Accounts receivable—affiliated companies	28		28
Inventory	65		83
Gas imbalances	35		10
Other current assets	56		14
Total current assets	520		549
Property, Plant and Equipment:
Property, plant and equipment	10,163		9,655
Less accumulated depreciation and amortization	819		665
Property, plant and equipment, net	9,344		8,990
Other Assets:
Intangible assets, net	363		383
Goodwill	1,068		1,068
Investment in equity method affiliates	349		198
Other	48		44
Total other assets	1,828		1,693
Total Assets	$	11,692	$	11,232
Current Liabilities:
Accounts payable	$	266	$	400
Accounts payable—affiliated companies	35		40
Current portion of long-term debt	—		204
Notes payable—commercial paper	95		—
Taxes accrued	47		20
Gas imbalances	11		13
Other	65		43
Total current liabilities	519		720
Other Liabilities:
Accumulated deferred income taxes, net	8		8
Notes payable—affiliated companies	363		363
Regulatory liabilities	16		16
Other	31		28
Total other liabilities	418		415
Long-Term Debt	1,929		1,916
Commitments and Contingencies (Note 12)
Partners’ Capital:
Enable Midstream Partners, LP Partners’ Capital	8,794		8,148
Noncontrolling interest	32		33
Total Partners’ Capital	8,826		8,181
Total Liabilities and Partners’ Capital	$	11,692	$	11,232

See Notes to the Unaudited Condensed Combined and Consolidated Financial Statements

Table of Contents

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
	2014			2013
	(In millions)
Cash Flows from Operating Activities:
Net income	$	410		$	1,502
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	205			148
Deferred income taxes	(1		)	(1,197		)
Impairments	1			12
Gain on sale/retirement of assets	4			2
Equity in earnings of equity method affiliates, net of distributions	—			8
Equity based compensation	9			—
Amortization of debt costs and discount (premium)	(1		)	—
Changes in other assets and liabilities:
Accounts receivable, net	(11		)	(37		)
Accounts receivable—affiliated companies	—			(2		)
Inventory	6			(9		)
Gas imbalance assets	(25		)	—
Income taxes receivable	—			20
Other current assets	(2		)	20
Other assets	10			(7		)
Accounts payable	(91		)	3
Accounts payable—affiliated companies	(5		)	7
Gas imbalance liabilities	(1		)	(6		)
Other current liabilities	50			11
Other liabilities	3			(3		)
Net cash provided by operating activities	561			472
Cash Flows from Investing Activities:
Capital expenditures	(586		)	(366		)
Decrease in notes receivable—affiliated companies	—			434
Return of investment in equity method affiliates	198			—
Investment in equity method affiliates	(187		)	—
Other, net	2			(5		)
Net cash provided by (used in) investing activities	(573		)	63
Cash Flows from Financing Activities:
Repayment of long term debt	(1,500		)	—
Proceeds from long term debt, net of issuance costs	1,635			1,046
Proceeds from revolving credit facility	115			590
Repayment of revolving credit facility	(487		)	(447		)
Increase in notes payable—commercial paper	95			—
Decrease of notes payable—affiliated companies	—			(1,542		)
Repayment of advance with affiliated companies	—			(139		)
Capital contributions from partners	464			43
Distributions to partners	(400		)	(62		)
Net cash provided by (used in) financing activities	(78		)	(511		)
Net Increase in Cash and Cash Equivalents	(90		)	24
Cash and Cash Equivalents at Beginning of Period	108			—
Cash and Cash Equivalents at End of Period	$	18		$	24

See Notes to the Unaudited Condensed Combined and Consolidated Financial Statements

Table of Contents

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS, continued

(Unaudited)



	Nine Months Ended September 30,
	2014		2013
	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	53	$	52
Income taxes (refunds), net	1		(9		)
Non-cash transactions:
Accounts payable related to capital expenditures	4		41
Issuance of common units upon interest acquisition of SESH (Note 7)	161		—
Acquisition of Enogex (Note 3)	—		3,788

See Notes to the Unaudited Condensed Combined and Consolidated Financial Statements

Table of Contents

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED COMBINED AND CONSOLIDATED STATEMENTS OF

ENABLE MIDSTREAM PARTNERS, LP PARENT NET EQUITY AND PARTNERS’ CAPITAL

(Unaudited)



	Partners’ Capital				Parent Net Investment			Accumulated Other Comprehensive Loss			Total Enable Midstream Partners, LP Partners’ Capital			Noncontrolling Interest			Total Partners’ Capital
	Units	Value			Value			Value			Value			Value			Value
	(In millions)
Balance as of December 31, 2012	—	$	—		$	3,221		$	(6	)	$	3,215		$	6		$	3,221
Net income	—	—			1,326			—			1,326			—			1,326
Contributions from (Distributions to) CenterPoint Energy prior to formation (Note 5)	—	—			(295		)	6			(289		)	—			(289		)
Balance as of April 30, 2013	—	—			4,252			—			4,252			6			4,258
Conversion to a limited partnership	227	4,252			(4,252		)	—			—			—			—
Issuance of units upon acquisition of Enogex on May 1, 2013	163	3,788			—			—			3,788			26			3,814
Net income	—	174			—			—			174			2			176
Distributions to partners	—	(62		)	—			—			(62		)	—			(62		)
Balance as of September 30, 2013	390	$	8,152		$	—		$	—		$	8,152		$	34		$	8,186

Balance as of December 31, 2013	390	$	8,148		$	—		$	—		$	8,148		$	33		$	8,181
Net income	—	408			—			—			408			2			410
Issuance of IPO common units	25	464			—			—			464			—			464
Issuance of common units upon interest acquisition of SESH	6	161			—			—			161			—			161
Distributions to partners	—	(397		)	—			—			(397		)	(3		)	(400		)
Equity based compensation	1	10			—			—			10			$	—		10
Balance as of September 30, 2014	422	$	8,794		$	—		$	—		$	8,794		$	32		$	8,826

See Notes to the Unaudited Condensed Combined and Consolidated Financial Statements

Table of Contents

ENABLE MIDSTREAM PARTNERS, LP

NOTES TO THE UNAUDITED CONDENSED COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

Organization

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

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

At September 30, 2014, CenterPoint Energy held approximately 55.4% of the limited partner interests in the Partnership, or 94,126,366 common units and 139,704,916 subordinated units, and OGE Energy held approximately 26.3% of the limited partner interests in the Partnership, or 42,832,291 common units and 68,150,514 subordinated units. The limited partner interests of the Partnership have limited voting rights on matters affecting the business. As such, limited partners do not have rights to elect the Partnership’s General Partner (Enable GP) on an annual or continuing basis and may not remove Enable GP without at least a 75% vote by all unitholders, including all units held by the Partnership’s limited partners, and Enable GP and its affiliates, voting together as a single class.

Upon conversion to a limited partnership on May 1, 2013, the Partnership’s earnings are generally no longer subject to income tax (other than Texas state margin taxes and taxes associated with the Partnership's corporate subsidiary) and are taxable at the individual partner level. As a result of the conversion to a partnership immediately prior to formation, CenterPoint Energy assumed all outstanding current income tax liabilities and the Partnership derecognized the deferred income tax assets and liabilities by recording an income tax benefit of $1.24 billion. Consequently, the Combined and Consolidated Statements of Income do not include an income tax provision on income earned on or after May 1, 2013 (other than Texas state margin taxes and taxes associated with the Partnership's corporate subsidiary). See Note 13 for further discussion of the Partnership’s income taxes.

Prior to May 1, 2013, the financial statements of the Partnership include EGT, MRT and the non-rate regulated natural gas gathering, processing and treating operations, which were under common control by CenterPoint Energy, and a 50% interest in SESH. Through the Partnership's formation on May 1, 2013, CenterPoint Energy retained certain assets and liabilities and related balances in accumulated other comprehensive loss, historically held by the Partnership, such as certain notes payable—affiliated companies to CenterPoint Energy and benefit plan obligations. Additionally, the Partnership distributed a 25.05% interest in SESH to CenterPoint Energy, subject to future acquisition by the Partnership through put and call options discussed in Note 7. On May 1, 2013, OGE Energy and ArcLight indirectly contributed 100% of the equity interests in Enogex to the Partnership in exchange for limited partner interests and, for OGE Energy only, interests in Enable GP. The Partnership concluded that the Partnership formation on May 1, 2013 was considered a business combination, and for accounting purposes, the Partnership was the acquirer of Enogex. Subsequent to May 1, 2013, the financial statements of the Partnership are consolidated to reflect the acquisition of Enogex. See Note 3 for further discussion of the acquisition of Enogex. For the period from May 1, 2013 through May 29, 2014, the financial statements reflect a 24.95% interest in SESH. For the period of May 30, 2014 through September 30, 2014, the financial statements reflect a 49.90% interest in SESH. See Note 7 for further discussion of SESH.

Table of Contents

In addition, at September 30, 2014, as a result of the acquisition of Enogex on May 1, 2013, the Partnership held a 50% ownership interest in Atoka Midstream LLC (Atoka). At September 30, 2014, the Partnership consolidated Atoka in its Condensed Combined and Consolidated Financial Statements as Enable Oklahoma acted as the managing member of Atoka and had control over the operations of Atoka.

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

Basis of Presentation

The accompanying condensed combined and consolidated financial statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with GAAP have been omitted. The accompanying condensed combined and consolidated financial statements and related notes should be read in conjunction with the combined and consolidated financial statements and related notes included in the Prospectus.

For accounting and financial reporting purposes, (i) the formation of the Partnership is considered a contribution of real estate by CenterPoint Energy and is reflected at CenterPoint Energy’s historical cost as of May 1, 2013 and (ii) the Partnership acquired Enogex on May 1, 2013.

The condensed combined and consolidated financial statements for the nine months ended September 30, 2013 have been prepared from the historical accounting records maintained by CenterPoint Energy for the Partnership until May 1, 2013 and may not necessarily be indicative of the condition that would have existed or the results of operations if the Partnership had been operated as a separate and unaffiliated entity. All of the Partnership’s historical combined entities were under common control and management for the periods presented until May 1, 2013, and all intercompany transactions and balances are eliminated in combination and consolidation, as applicable. Beginning on May 1, 2013, the Partnership consolidated Enogex and all previously combined entities of the Partnership.

These condensed combined and consolidated financial statements and the related financial statement disclosures reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. Amounts reported in the Partnership’s Condensed Combined and Consolidated Statements of Income are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures and (d) acquisitions and dispositions of businesses, assets and other interests.

For a description of the Partnership’s reportable business segments, see Note 15.

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.

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 condensed combined and consolidated financial statements reflect the effects of the reverse unit split.

Table of Contents

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

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

(2) New Accounting Pronouncements

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

(3) Acquisition of Enogex

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

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

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

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

Table of Contents



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

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

The amounts of Enogex’s revenue, operating income, net income and net income attributable to the Partnership included in the Partnership’s Combined and Consolidated Statement of Income for the period from May 1, 2013 through September 30, 2013, before eliminations, are as follows (in millions):



Revenues	$	861
Operating income	63
Net income	54
Net income attributable to Enable Midstream Partners, LP	52

Impact on Depreciation

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

Pro forma Results of Operations

The Partnership’s pro forma results of operations in the combined entity had the acquisition of Enogex been completed on January 1, 2013 are as follows:



	Nine Months Ended September 30, 2013
	(In millions)
Pro forma results of operations:
Pro forma revenues	$	2,296
Pro forma operating income	356
Pro forma net income	1,522
Pro forma net income attributable to Enable Midstream Partners, LP	1,520

The pro forma consolidated results of operations include adjustments to:


•	Include the historical results of Enogex beginning on January 1, 2013;


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


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

Table of Contents


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

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

(4) Earnings Per Limited Partner Unit

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

Basic and diluted earnings per limited partner unit is calculated by dividing the limited partners’ interest in net income by the weighted average number of limited partner units outstanding during the period. Any common units issued during the period are included on a weighted average basis for the days in which they were outstanding. There was no dilutive effect of unit-based awards during the three and nine months ended September 30, 2014.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(In millions, except per unit data)
Net income attributable to Enable Midstream Partners, LP	$	139	$	104	$	408	$	174
Less general partner interest in net income	—		—		—		—
Limited partner interest in net income attributable to Enable Midstream Partners, LP	$	139	$	104	$	408	$	174
Net income allocable to common units	$	71	$	104	$	282	$	174
Net income allocable to subordinated units	68		—		126		—
Limited partner interest in net income attributable to Enable Midstream Partners, LP	$	139	$	104	$	408	$	174
Basic and diluted weighted average number of outstanding limited partner units
Common units	214		390		281		390
Subordinated units	208		—		128		—
Total	422		390		409		390
Basic and diluted earnings per limited partner unit
Common units	$	0.33	$	0.27	$	1.00	$	0.45
Subordinated units	$	0.33	$	—	$	0.98	$	—

(5) Enable Midstream Partners, LP Parent Net Equity and Partners’ Capital

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

Table of Contents



	Amounts retained prior to May 1, 2013
	(In millions)
Contributions from (Distributions to) CenterPoint Energy
Cash	$	40
Pension and postretirement plans	22
Deferred financing cost	6
Investment in 25.05% of SESH (see Note 7)	(197		)
Increase in Notes payable-affiliated companies	(143		)
Decrease in Notes receivable-affiliated companies	(45		)
Income tax obligations, net	28
Net distributions to CenterPoint Energy prior to formation	$	(289	)

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

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

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

Quarter Ended

Record Date

Payment Date

Per Unit Distribution

Total Cash Distribution

June 30, 2014 ⁽¹⁾

August 4, 2014

August 14, 2014

0.2464

104

September 30, 2014 ⁽²⁾

November 4, 2014

November 14, 2014

0.3025

128

_____________________


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


(2)	The board of directors of Enable GP declared this $0.3025 per common unit cash distribution on October 24, 2014, to be paid on November 14, 2014, to unitholders of record at the close of business on November 4, 2014.

General Partner Interest and Incentive Distribution Rights

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

Subordinated Units

All subordinated units are held by CenterPoint Energy and OGE Energy. These units are considered subordinated because during the subordination period (as defined in the Prospectus), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.2875 per common unit, which amount is defined in

Table of Contents

the partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units.

Subordination Period

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

(6) Intangible Assets, Net

Prior to May 1, 2013, the Partnership did not have any intangible assets. The Partnership recorded $401 million in intangible assets associated with customer relationships due to the acquisition of Enogex.

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

The Partnership recorded amortization expense of $7 million during each of the three months ended September 30, 2014 and 2013, respectively, and $20 million and $11 million during each of the nine months ended September 30, 2014 and 2013, respectively.

(7) Investments in Equity Method Affiliates

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

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

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

Table of Contents

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 distribution 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 the Partnership's 49.90% investment in SESH to $349 million as of September 30, 2014. 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.

Investment in Equity Method Affiliates:



	(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	12
Contributions to equity method affiliate	2
Distributions from equity method affiliate	(13		)
Balance as of September 30, 2014	$	349

Equity in Earnings of Equity Method Affiliates:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(In millions)
SESH	$	5	$	3	$	12	$	12

Distributions from Equity Method Affiliates:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(In millions)
SESH ⁽¹⁾	$	7	$	3	$	13	$	20

_____________________


(1)	Excludes $198 million in special distributions for the return of investment in SESH for the nine month period ended September 30, 2014.

Summarized financial information of SESH is presented below:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(In millions)
Income Statements:
Revenues	$	27	$	28	$	80	$	81
Operating income	17		18		50		49
Net income	12		13		34		34

Table of Contents

(8) Debt

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

The Partnership also has a $1.4 billion senior unsecured revolving credit facility (Revolving Credit Facility) that is scheduled to expire on May 1, 2018. As of September 30, 2014, there were no principal advances and $2 million in letters of credit outstanding under the Revolving Credit Facility. However, as discussed below, commercial paper borrowings effectively reduce our borrowing capacity under this Revolving Credit Facility.

The Revolving Credit Facility permits outstanding borrowings to bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s applicable credit ratings. As of September 30, 2014, the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was 1.625% based on the Partnership’s credit ratings. In addition, the Revolving Credit Facility requires the Partnership to pay a fee on unused commitments. The commitment fee is based on the Partnership’s applicable credit rating from the rating agencies. As of September 30, 2014, the commitment fee under the Revolving Credit Facility was 0.25% per annum based on the Partnership’s credit ratings.

In January 2014, the Partnership commenced a commercial paper program, pursuant to which the Partnership is authorized to issue up to $1.4 billion of commercial paper. The commercial paper program is supported by our Revolving Credit Facility, and outstanding commercial paper effectively reduces our borrowing capacity thereunder. As of September 30, 2014, $95 million was outstanding under our commercial paper program. Any reduction in our credit ratings could prevent us from accessing the commercial paper markets.

As of September 30, 2014, the Partnership’s debt included $250 million of 6.25% senior notes due March 2020 (the Enable Oklahoma Senior Notes). The Enable Oklahoma Senior Notes have $30 million unamortized premium at September 30, 2014.

Unamortized debt expense of $17 million and $9 million at September 30, 2014 and December 31, 2013, respectively, is classified in Other Assets in the Condensed Consolidated Balance Sheets and is being amortized over the life of the respective debt. Unamortized premium on long-term debt of $30 million and $37 million at September 30, 2014 and December 31, 2013, respectively, is classified as either Long-Term Debt or Current Portion of Long-Term Debt, consistent with the underlying debt instrument, in the Condensed Consolidated Balance Sheets and is being amortized over the life of the respective debt.

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

As of September 30, 2014, the Partnership and Enable Oklahoma were in compliance with all of their debt agreements, including financial covenants.

(9) Fair Value Measurements

Certain assets and liabilities are recorded at fair value in the Condensed Consolidated Balance Sheets and are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities are as follows:

Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on the NYMEX and settled through a NYMEX clearing broker.

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. Instruments classified as Level 2 include over-the-counter NYMEX natural gas swaps, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX pricing, and over-the-counter WTI crude swaps for condensate sales.

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect the Partnership’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Partnership develops these inputs based on the best information available, including the Partnership’s own data.

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

The Partnership determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the period ended September 30, 2014, there were no transfers between Level 1, 2, and 3 investments.

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

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 Condensed Consolidated Balance Sheets. The Partnership has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.

The following tables summarize the Partnership’s assets and liabilities that are measured at fair value on a recurring basis at September 30, 2014 and December 31, 2013:



September 30, 2014	Commodity Contracts					Gas Imbalances ⁽¹⁾
	Assets		Liabilities			Assets ⁽²⁾		Liabilities ⁽³⁾
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	4	$	(2	)	$	—	$	—
Significant other observable inputs (Level 2)	1		—			33		$	11
Unobservable inputs (Level 3)	1		—			—		$	—
Total fair value	6		(2		)	33		$	11
Netting adjustments	—		—			—		$	—
Total	$	6	$	(2	)	$	33	$	11



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

______________________

(1)

The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. Gas imbalances held by Enable Oklahoma are valued using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices. There were no netting adjustments as of September 30, 2014 and December 31, 2013.


(2)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $1 million and $2 million at September 30, 2014 and December 31, 2013, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.


(3)	Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1 million and $3 million at September 30, 2014 and December 31, 2013, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

Estimated Fair Value of Financial Instruments

The fair values of all accounts receivable, notes receivable, accounts payable, notes payable-commercial paper, and other such financial instruments on the Condensed 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 September 30, 2014 and December 31, 2013.



	September 30, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-Term Debt
Long-term notes payable - affiliated companies (Level 2)	$	363	$	366	$	363	$	363
Revolving Credit Facility (Level 2)⁽¹⁾	—		—		333		333
Term Loan Facility (Level 2)	—		—		1,050		1,050
Enable Oklahoma Term Loan (Level 2)	—		—		250		250
Enable Oklahoma Senior Notes (Level 2)⁽²⁾	280		286		487		477
Enable Midstream Partners, LP 2019, 2024 and 2044 Notes (Level 2)	1,649		1,641		—		—

___________________


(1)	Borrowing capacity is reduced by our borrowings outstanding under the commercial paper program. $95 million of commercial paper was outstanding as of September 30, 2014 and none was outstanding as of December 31, 2013.


(2)	No amount was included in the current portion of long term debt as of September 30, 2014 and $204 million is included as of December 31, 2013.

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

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

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

At September 30, 2014 and December 31, 2013, no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities.

(10) Derivative Instruments and Hedging Activities

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

Commodity Price Risk

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


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


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


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

Normal purchases and normal sales contracts are not recorded in Other Assets or Liabilities in the Condensed 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.

Table of Contents

The Partnership recognizes its non-exchange traded derivative instruments as Other Assets or Liabilities in the Condensed 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 Condensed Consolidated Balance Sheets.

As of September 30, 2014 and December 31, 2013, the Partnership had no derivative instruments that were designated as cash flow or fair value hedges for accounting purposes.

Credit Risk

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

Derivatives Not Designated As Hedging Instruments

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

Quantitative Disclosures Related to Derivative Instruments

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

As of September 30, 2014, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes.



	Gross Notional Volume
	Purchases	Sales
Natural gas—TBtu⁽¹⁾
Physical	7	39
Fixed futures/swaps	3	15
Basis futures/swaps	6	18
Condensate—MBbl⁽²⁾
Futures/swaps	—	168
Natural gas liquids—MBbl⁽³⁾
Futures/swaps	—	204

____________________


(1)	85.4 percent of the natural gas contracts have durations of one year or less, 9.8 percent have durations of more than one year and less than two years and 4.8 percent have durations of more than two years.


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


(3)	100.0 percent of the natural gas liquids contracts have durations of one year or less.

Table of Contents

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



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

____________________


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

Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheet as of September 30, 2014 are as follows:



		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities
		(In millions)
Derivatives not designated as hedging instruments
Natural gas
Financial futures/swaps	Other Current	$	6	$	2
Physical purchases/sales	Other Current	1		—
Total gross derivatives ⁽¹⁾		$	7	$	2

_____________________


(1)	See Note 9 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheet as of September 30, 2014.

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



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

_______________________


(1)	See Note 9 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheet as of December 31, 2013.

Income Statement Presentation Related to Derivative Instruments

The following tables present the effect of derivative instruments on the Partnership’s Condensed Consolidated Statement of Income for the three and nine months ended September 30, 2014.

Table of Contents



	Amounts Recognized in Income
	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013		2014			2013
	(In millions)
Natural gas physical purchases/sales gains (losses)	$	(1	)	$	1	$	(1	)	$	(2	)
Natural gas financial futures/swaps gains (losses)	3			—		4			1
Condensate financial futures/swaps gains (losses)	$	3		$	—	$	2		$	—
Total	$	5		$	1	$	5		$	(1	)

For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended September 30, 2014 and 2013, if any, are reported in Revenues.

Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody’s Investors Services or Standard & Poor’s Ratings Services were to lower the Partnership’s senior unsecured debt rating to a below investment grade rating, at September 30, 2014, the Partnership would have been required to post no cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position at September 30, 2014. In addition, the Partnership could be required to provide additional credit assurances in future dealings with third parties, which could include letters of credit or cash collateral.

(11) Related Party Transactions

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

The Partnership’s revenues from affiliated companies accounted for 5% and 8% of revenues during the three months ended September 30, 2014 and 2013, respectively, and 5% and 10% of revenues during the nine months ended September 30, 2014 and 2013, respectively. Amounts of revenues from affiliated companies included in the Partnership’s Condensed Combined and Consolidated Statements of Income are summarized as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(In millions)
Gas transportation and storage - CenterPoint Energy	$	22	$	23	$	82	$	82
Gas sales - CenterPoint Energy	1		22		17		46
Gas transportation and storage - OGE Energy ⁽¹⁾	9		12		31		20
Gas sales - OGE Energy⁽¹⁾	5		9		10		11
Total revenues - affiliated companies	$	37	$	66	$	140	$	159

____________________

(1)

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

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

Table of Contents



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(In millions)
Cost of goods sold - CenterPoint Energy	$	—	$	1	$	2	$	4
Cost of goods sold - OGE Energy	8		3		14		5
Total cost of goods sold - affiliated companies	$	8	$	4	$	16	$	9

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

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

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

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(In millions)
Seconded Employee Costs - CenterPoint Energy ⁽¹⁾	$	32	$	36	$	101	$	61
Corporate Services - CenterPoint Energy	6		9		23		31
Seconded Employee Costs - OGE Energy ⁽²⁾	25		26		78		41
Corporate Services - OGE Energy ⁽²⁾	3		6		13		10
Total corporate services and seconded employees expense	$	66	$	77	$	215	$	143

_________________________


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


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

The Partnership has outstanding long-term notes payable—affiliated companies to CenterPoint Energy at both September 30, 2014 and December 31, 2013 of $363 million which mature in 2017. Notes having an aggregate principal amount of approximately $273 million bear a fixed interest rate of 2.10% and notes having an aggregate principal amount of approximately $90 million bear a fixed interest rate of 2.45%.

The Partnership recorded affiliated interest expense to CenterPoint Energy on note payable—affiliated companies of $2 million during each of the three months ended September 30, 2014 and 2013, respectively, and $6 million and $33 million during the nine months ended September 30, 2014 and 2013, respectively.

Table of Contents

The Partnership recorded no interest income—affiliated companies from CenterPoint Energy on notes receivable—affiliated companies and $1 million during each of the three months ended September 30, 2014 and 2013, respectively, and no interest income-affiliated companies and $9 million during each of the nine months ended September 30, 2014 and 2013, respectively.

(12) Commitments and Contingencies

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.

(13) Income Taxes

The items comprising income tax expense are as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In millions)
Provision (benefit) for current income taxes
Federal	$	1		$	3		$	2		$	1
State	—			—			1			1
Total provision (benefit) for current income taxes	1			3			3			2
Provision (benefit) for deferred income taxes, net
Federal	$	(1	)	(2		)	$	(2	)	$	(1,039	)
State	1			—			1			(158		)
Total provision (benefit) for deferred income taxes, net	—			(2		)	(1		)	(1,197		)
Total income tax expense (benefit)	$	1		$	1		$	2		$	(1,195	)

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

As a result of the conversion to a limited partnership, CenterPoint Energy assumed all outstanding current income tax liabilities and the deferred income tax assets and liabilities were eliminated by recording a provision for income tax benefit of $1.24 billion.

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

(14) Equity Based Compensation

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

Table of Contents

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

The following table summarizes the Partnership’s compensation expense for the three and nine months ended September 30, 2014 and 2013 related to performance units, restricted units, and phantom units for the Partnership's employees.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(In millions)
Performance units	$	1	$	—	$	1	$	—
Restricted units	3		—		8		—
Phantom units	1		—		1		—
Total compensation expense	$	5	$	—	$	10	$	—

Performance Units

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

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

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

Table of Contents



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

Restricted Units

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

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

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



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

Restricted units granted to the Partnership's employees	243,616
Fair value of restricted units granted	$24.65 - $25.50

Phantom Units

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

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

Table of Contents



	2014
Phantom units granted to the Partnership's employees	100,000
Fair value of phantom units granted	$	23.16

Units Outstanding

A summary of the activity for the Partnership's performance units, restricted units, and phantom units applicable to the Partnership’s employees at September 30, 2014 and changes in 2014 are shown in the following table.



	Performance Units				Restricted Units				Phantom Units
	Number of Units		Aggregate Intrinsic Value		Number of Units		Aggregate Intrinsic Value		Number of Units		Aggregate Intrinsic Value
	(In millions, except unit data)
Units Outstanding at December 31, 2013	—				—				—
Granted⁽¹⁾	563,963				931,116				100,000
Vested	(1,545	)			(150,515	)			(500	)
Forfeited	(7,034	)			(2,901	)			(6,000	)
Units Outstanding at September 30, 2014	555,384		$	13	777,700		$	19	93,500		$	2
Units Fully Vested at September 30, 2014	1,545		$	—	150,515				500		$	—

_____________________


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

Unrecognized Compensation Cost

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



	September 30, 2014
	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance Units	$	13	2.89
Restricted Units	14		1.80
Phantom Units	1		0.58
Total	$	28

As of September 30, 2014, there were 11,519,555 units available for issuance under the long term incentive plan.

(15) Reportable Business Segments

The Partnership’s determination of reportable business 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 business segments are the same as those described in the summary of significant accounting policies excerpt in the Partnership’s audited 2013 combined and consolidated financial statements included in the Prospectus, which explain that some executive benefit costs of the Partnership prior to May 1, 2013 have not been allocated to business segments. The Partnership uses operating income as the measure of profit or loss for its business segments.

The Partnership’s assets and operations are organized into two business segments: (i) Gathering and Processing, which primarily provides natural gas gathering, processing and fractionation services and crude oil gathering for our producer customers, and (ii) Transportation and Storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to natural gas producers, utilities and industrial customers. Effective May 1, 2013, the intrastate natural gas pipeline

Table of Contents

operations acquired from Enogex were combined with the interstate pipelines in the transportation and storage segment and the non-rate regulated natural gas gathering, processing and treating operations acquired from Enogex were combined with in the gathering and processing segment.

Financial data for business segments and services are as follows:



Three Months Ended September 30, 2014	Gathering and Processing		Transportation and Storage⁽¹⁾		Eliminations			Total
	(In millions)
Revenues	$	604	$	341	$	(142	)	$	803
Cost of goods sold, excluding depreciation and amortization	382		198		(141		)	439
Operation and maintenance	76		53		(1		)	128
Depreciation and amortization	41		28		—			69
Impairment	1		—		—			1
Taxes other than income tax	8		6		—			14
Operating income	$	96	$	56	$	—		$	152
Total assets	$	8,169	$	5,400	$	(1,877	)	$	11,692
Capital expenditures	$	227	$	25	$	(4	)	$	248

Three Months Ended September 30, 2013	Gathering and Processing		Transportation and Storage⁽¹⁾		Eliminations			Total
	(In millions)
Revenues	$	544	$	353	$	(105	)	$	792
Cost of goods sold, excluding depreciation and amortization	351		212		(104		)	459
Operation and maintenance	68		57		(1		)	124
Depreciation and amortization	37		30		—			67
Impairment	12		—		—			12
Taxes other than income tax	6		9		—			15
Operating income	$	70	$	45	$	—		$	115
Total assets as of December 31, 2013	$	7,157	$	5,717	$	(1,642	)	$	11,232
Capital expenditures	$	160	$	37	$	—		$	197

_____________________

(1)

Transportation and Storage recorded equity income of $5 million and $3 million for the three months ended September 30, 2014 and 2013, respectively, from its interest in SESH, a jointly-owned pipeline. These amounts are included in Equity in earnings of equity method affiliates under the Other Income (Expense) caption. Transportation and Storage’s investment in SESH was $349 million and $198 million as of September 30, 2014 and December 31, 2013, respectively, and is included in Investments in equity method affiliates. The Partnership reflected a 50% interest in SESH until May 1, 2013 when the Partnership distributed a 25.05% interest in SESH to CenterPoint Energy. For the period of May 1, 2013 through May 29, 2014 the Partnership reflected a 24.95% interest in SESH. On May 30, 2014, CenterPoint Energy contributed its 24.95% interest in SESH to the Partnership. As of September 30, 2014, the Partnership owns 49.90% interest in SESH. See Note 7 for further discussion regarding SESH.

Table of Contents



Nine Months Ended September 30, 2014	Gathering and Processing		Transportation and Storage⁽¹⁾		Eliminations			Total
	(In millions)
Revenues	$	1,882	$	1,219	$	(469	)	$	2,632
Cost of goods sold, excluding depreciation and amortization	1,250		768		(468		)	1,550
Operation and maintenance	219		165		(1		)	383
Depreciation and amortization	118		87		—			205
Impairment	1		—		—			1
Taxes other than income tax	18		23		—			41
Operating income	$	276	$	176	$	—		$	452
Total assets	$	8,169	$	5,400	$	(1,877	)	$	11,692
Capital expenditures	$	522	$	69	$	(5	)	$	586

Nine Months Ended September 30, 2013	Gathering and Processing		Transportation and Storage⁽¹⁾		Eliminations			Total
	(In millions)
Revenues	$	1,135	$	784	$	(254	)	$	1,665
Cost of goods sold, excluding depreciation and amortization	673		406		(252		)	827
Operation and maintenance	155		149		(2		)	302
Depreciation and amortization	80		68		—			148
Impairment	12		—		—			12
Taxes other than income tax	13		24		—			37
Operating income	$	202	$	137	$	—		$	339
Total assets as of December 31, 2013	$	7,157	$	5,717	$	(1,642	)	$	11,232
Capital expenditures	$	269	$	97	$	—		$	366

_____________________

(1)

Transportation and Storage recorded equity income of $12 million and $12 million for the nine months ended September 30, 2014 and 2013, respectively, from its interest in SESH, a jointly-owned pipeline. These amounts are included in Equity in earnings of equity method affiliates under the Other Income (Expense) caption. Transportation and Storage’s investment in SESH was $349 million and $198 million as of September 30, 2014 and December 31, 2013, respectively, and is included in Investments in equity method affiliates. The Partnership reflected a 50% interest in SESH until May 1, 2013 when the Partnership distributed a 25.05% interest in SESH to CenterPoint Energy. For the period of May 1, 2013 through May 29, 2014 the Partnership reflected a 24.95% interest in SESH. On May 30, 2014, CenterPoint Energy contributed its 24.95% interest in SESH to the Partnership. As of September 30, 2014, the Partnership owns 49.90% interest in SESH. See Note 7 for further discussion regarding SESH.

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our unaudited condensed combined and consolidated financial statements and the related notes included herein and our audited combined and consolidated financial statements for the year ended December 31, 2013, included in the Prospectus. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Please read “Forward-Looking Statements.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We are a large-scale, growth-oriented limited partnership formed to own, operate and develop strategically located natural gas and crude oil infrastructure assets. We serve current and emerging production areas in the United States, including several

Table of Contents

unconventional shale resource plays and local and regional end-user markets in the United States. Our assets and operations are organized into two business 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. In both business segments, we generate a substantial portion of our gross margin under long-term, fee-based agreements that minimize our direct exposure to commodity price fluctuations.

Our natural gas gathering and processing assets are located in five states and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex basins. We also own a crude oil gathering business in the Bakken shale formation in the Williston Basin that commenced initial operations in November 2013. We are continuing to construct additional crude oil gathering capacity in this area. Our natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

General Trends and Outlook

We expect our business to continue to be affected by the key trends included in the Prospectus. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Outlook

We plan to continue to invest in midstream infrastructure projects, including investments in natural gas gathering, natural gas processing, crude oil gathering and natural gas transportation assets. In 2014 we anticipate capital expenditures could range from $870 million to $940 million, inclusive of capital identified as maintenance spending.

The growth in our gathering and processing business is driven primarily by producer activity across our footprint, particularly in the Williston and Anadarko basins. The current prices of natural gas liquids and crude oil prices favor drilling activity in the Williston and Anadarko basins, and we have seen significant producer activity within and near our gathering systems in these basins. At current drilling levels, we expect that crude oil and natural gas gathering volumes will continue to increase in these areas. The Ark-La-Tex and Arkoma basins are primarily lean gas basins that are less economic to produce at current commodity prices compared to other basins in the country. We anticipate that natural gas gathering volumes in these areas will continue to decline at current activity levels; however, much of the impact of these decreased volumes is expected to be offset by payments under minimum volume commitment contracts.

Our transportation and storage business is driven primarily by producer activity around our pipeline systems as well as natural gas end-user demand. Our pipelines are connected to industrial end users and utilities, such as local distribution companies, or LDCs, and power generators, and we continue to see demand for transportation and storage services from these customers. For example, MRT recently extended firm transportation and storage contracts with Laclede Gas Company, MRT’s largest customer, through 2017 and 2018 at existing contract demand levels. Producer activity around our Anadarko pipeline system continues to drive demand on our intrastate and interstate transportation systems. For example, EGT contracted with a producer earlier this year for a 10-year firm transportation service agreement that provides for transportation of up to 230,000 dekatherms per day by November 1, 2015. Some areas of our systems, such as EGT’s Carthage, Texas, to Perryville, Louisiana, pipeline, have contracts with higher rates than current market rates in these areas. We anticipate lower margins in these areas as contracts with higher rates expire should market rates remain at current levels.

Results of Operations

The historical financial information included below reflects the combined assets, liabilities and operations of the entities comprising CenterPoint Energy’s reportable business segments for periods ending prior to May 1, 2013 and the consolidated assets, liabilities and operations of these reportable business segments and Enogex for periods ending on or after May 1, 2013. With respect to periods ending prior to May 1, 2013, we refer to CenterPoint Energy’s Interstate Pipelines segment as our Transportation and Storage segment and CenterPoint Energy’s Field Services segment as our Gathering and Processing segment.

Table of Contents



Three Months Ended September 30, 2014	Gathering and Processing		Transportation and Storage		Eliminations			Enable Midstream Partners, LP
	(In millions)
Revenues	$	604	$	341	$	(142	)	$	803
Cost of goods sold (excluding depreciation and amortization)	382		198		(141		)	439
Gross margin on revenues	222		143		(1		)	364
Operation and maintenance	76		53		(1		)	128
Depreciation and amortization	41		28		—			69
Impairment	1		—		—			1
Taxes other than income tax	8		6		—			14
Operating income	$	96	$	56	$	—		$	152
Equity in earnings of equity method affiliates	$	—	$	5	$	—		$	5



Three Months Ended September 30, 2013	Gathering and Processing		Transportation and Storage		Eliminations			Enable Midstream Partners, LP
	(In millions)
Revenues	$	544	$	353	$	(105	)	$	792
Cost of goods sold (excluding depreciation and amortization)	351		212		(104		)	459
Gross margin on revenues	193		141		(1		)	333
Operation and maintenance	68		57		(1		)	124
Depreciation and amortization	37		30		—			67
Impairment	12		—		—			12
Taxes other than income tax	6		9		—			15
Operating income	$	70	$	45	$	—		$	115
Equity in earnings of equity method affiliates	$	—	$	3	$	—		$	3



Nine Months Ended September 30, 2014	Gathering and Processing		Transportation and Storage		Eliminations			Enable Midstream Partners, LP
	(In millions)
Revenues	$	1,882	$	1,219	$	(469	)	$	2,632
Cost of goods sold (excluding depreciation and amortization)	1,250		768		(468		)	1,550
Gross margin on revenues	632		451		(1		)	1,082
Operation and maintenance	219		165		(1		)	383
Depreciation and amortization	118		87		—			205
Impairment	1		—		—			1
Taxes other than income tax	18		23		—			41
Operating income	$	276	$	176	$	—		$	452
Equity in earnings of equity method affiliates	$	—	$	12	$	—		$	12

Table of Contents



Nine Months Ended September 30, 2013	Gathering and Processing		Transportation and Storage		Eliminations			Enable Midstream Partners, LP
	(In millions)
Revenues	$	1,135	$	784	$	(254	)	$	1,665
Cost of goods sold (excluding depreciation and amortization)	673		406		(252		)	827
Gross margin on revenues	462		378		(2		)	838
Operation and maintenance	155		149		(2		)	302
Depreciation and amortization	80		68		—			148
Impairment	12		—		—			12
Taxes other than income tax	13		24		—			37
Operating income	$	202	$	137	$	—		$	339
Equity in earnings of equity method affiliates	$	—	$	12	$	—		$	12



	Three Months Ended September 30,		Nine Months Ended September 30,
	2014	2013	2014	2013
Operating Data:
Gathered volumes—TBtu	306	320	913	790
Gathered volumes—TBtu/d	3.32	3.48	3.34	2.89
Natural gas processed volumes—TBtu	147	137	418	264
Natural gas processed volumes—TBtu/d	1.60	1.49	1.53	0.97
NGLs produced—MBbl/d⁽¹⁾	68.11	63.16	67.63	38.92
NGLs sold—MBbl/d⁽¹⁾⁽³⁾	68.87	63.35	69.60	39.17
Condensate sold—MBbl/d	3.52	2.26	4.31	1.47
Crude Oil - Gathered volumes—MBbl/d⁽²⁾	4.51	—	2.37	—
Transported volumes—TBtu	418	417	1,373	1,183
Transportation volumes—TBtu/d	4.54	4.53	5.02	4.32
Interstate firm contracted capacity—Bcf/d	7.50	7.56	8.69	7.74
Intrastate average deliveries—TBtu/d	1.66	1.66	1.62	0.88

_____________________


(1)	Excludes condensate.


(2)	Initial operation of our crude oil gathering system began on November 1, 2013.


(3)	NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.

Gathering and Processing

Three months ended September 30, 2014 compared to three months ended September 30, 2013. Our gathering and processing business segment reported operating income of $96 million in the three months ended September 30, 2014 compared to $70 million in the three months ended September 30, 2013. Operating income increased $26 million primarily from increased gross margin of $29 million and decreased impairment charges of $11 million, partially offset by an increase in operation and maintenance expenses of $8 million, an increase in depreciation and amortization of $4 million and an increase in taxes other than income tax of $2 million, during the three months ended September 30, 2014.

Our gathering and processing business segment gross margin increased $29 million primarily due to higher processing margin of $30 million due to higher processed volumes in the Anadarko and Ark-La-Tex basins, higher gathering margins in the Ark-La-Tex and Arkoma basins of $3 million, and higher crude oil gathering margin of $2 million, partially offset by $6 million due to higher cost of goods sold on measurement and communication services to third parties.

Our gathering and processing business segment operation and maintenance expenses increased $8 million primarily due to an increase in general and administrative expenses related to an increased payroll-related expense of $2 million to support business growth, an increase in integration costs of $3 million, an increase in non-capital costs of $3 million, a write down of materials and

Table of Contents

supplies inventory of $3 million and a loss on sale of assets of $5 million, partially offset by a decrease in expenses related to measurement and communication services to third parties of $8 million.

Our gathering and processing business segment depreciation and amortization increased $4 million due to assets placed in-service.

Our gathering and processing business segment impairment decreased $11 million due to a decrease in impairment of Service Star of $12 million, partially offset by an increase in impairment of assets held for sale of $1 million.

Our gathering and processing business segment taxes other than income tax increased $2 million due to increased ad valorem taxes as a result of additional assets placed in service.

Nine months ended September 30, 2014 compared to nine months ended September 30, 2013. Our gathering and processing business segment reported operating income of $276 million in the nine months ended September 30, 2014 compared to $202 million in the nine months ended September 30, 2013. Operating income increased $74 million primarily from increased gross margin of $170 million and decreased impairment charges of $11 million, partially offset by an increase in operation and maintenance expenses of $64 million, an increase in depreciation and amortization of $38 million and an increase in taxes other than income tax of $5 million, during the nine months ended September 30, 2014.

Our gathering and processing business segment gross margin increased $170 million primarily due to the acquisition of Enogex, resulting in an increase to margin of $138 million, higher natural gas prices of $11 million, higher processing margin of $29 million due to higher processed volumes in the Anadarko and Ark-La-Tex basins, and higher crude oil gathering margin of $2 million, partially offset by $10 million due to lower measurement and communication services to third parties.

Our gathering and processing business segment operation and maintenance expenses increased $64 million primarily due to the acquisition of Enogex, which contributed $51 million of operation and maintenance expenses and an increase in general and administrative expenses related to an increased payroll-related expense of $6 million to support business growth, an increase in integration costs of $3 million, an increase in non-capital costs of $4 million, a write down of materials and supplies inventory of $3 million and a loss on sale of assets of $5 million, partially offset by a decrease in expenses related to measurement and communication services to third parties of $8 million.

Our gathering and processing business segment depreciation and amortization increased $38 million due to the assets placed in-service from the 2013 acquisition of Enogex of $31 million and assets placed in service of $7 million.

Our gathering and processing business segment taxes other than income tax increased $5 million due to increased ad valorem taxes as a result of assets in service from the 2013 acquisition of Enogex of $4 million and other additional assets placed in service of $4 million, partially offset by the favorable settlement of a state and local tax dispute for $3 million less than the previously recognized reserve.

Transportation and Storage

Three months ended September 30, 2014 compared to three months ended September 30, 2013. Our transportation and storage business segment reported operating income of $56 million in the three months ended September 30, 2014 compared to $45 million in the three months ended September 30, 2013. Operating income increased $11 million primarily resulting from an increase in gross margin of $2 million, lower taxes other than income tax of $3 million, a decrease of $4 million in operation and maintenance expenses and a $2 million decrease in depreciation and amortization expenses during the three months ended September 30, 2014.

Our transportation and storage business segment gross margin increased $2 million primarily due to increased margin on ancillary services composed of a $5 million increase in margins from system optimization opportunities and a $2 million increase from operational synergies, as well as improvements to gross margin of $2 million due to other firm transportation revenues, partially offset by a decrease in liquid sales of $1 million, as well as a decrease in storage demand fees of $5 million, and balancing services of $1 million.

Our transportation and storage business segment operation and maintenance expenses decreased $4 million due to a decrease in corporate service costs of $10 million and a litigation settlement of $5 million in 2013, offset in 2014 by $2 million of insurance

Table of Contents

proceeds, partially offset by an increase in general and administrative expenses related to an increased payroll-related expense of $8 million to support business growth, an increase in non-capital costs of $3 million and a write down of materials and supplies inventory of $2 million.

Our transportation and storage business segment depreciation and amortization decreased $2 million primarily due to the settlement of the MRT rate case in 2013 of $2 million.

Our transportation and storage business segment taxes other than income tax decreased $3 million due to reduced ad valorem taxes.

Our transportation and storage business segment recorded equity in earnings of equity method affiliates of $5 million and $3 million for the three months ended September 30, 2014 and 2013, respectively, from our interest in SESH, a jointly owned pipeline. The $2 million increase in equity in earnings of equity method affiliates is attributable to an increase to our 24.95% interest in SESH on May 30, 2014, when CenterPoint Energy contributed an additional 24.95% interest in SESH to the Partnership.

Nine months ended September 30, 2014 compared to nine months ended September 30, 2013. Our transportation and storage business segment reported operating income of $176 million in the nine months ended September 30, 2014 compared to $137 million in the nine months ended September 30, 2013. Operating income increased $39 million primarily resulting from an increase in gross margin of $73 million and lower taxes other than income tax of $1 million, partially offset by an increase of $16 million in operation and maintenance expenses and a $19 million increase in depreciation and amortization expenses for the nine months ended September 30, 2014.

Our transportation and storage business segment gross margin increased $73 million primarily due to the acquisition of Enogex, which contributed $47 million to gross margin, increased margin on ancillary services composed of a $12 million increase in margins from system optimization opportunities and $3 million increase from operational synergies, a $3 million increase in liquid sales, and an increase to margins from off-system transportation revenues of $4 million, as well as continued improvements to gross margin of $6 million due to higher rates on transportation services for local distribution companies, and higher other firm transportation revenues of $3 million, partially offset by a decrease in storage demand fees of $5 million and balancing services of $1 million.

Our transportation and storage business segment operation and maintenance expenses increased $16 million due to the acquisition of Enogex, which contributed $19 million to operation and maintenance expenses, and an increase in general and administrative expenses related to an increased payroll-related expense of $13 million to support business growth, an increase in non-capital costs of $3 million, a write down of materials and supplies inventory of $2 million, partially offset by a decrease in gas control, volume control and customer service relocation costs of $4 million, a decrease in corporate service costs of $10 million, and a litigation settlement of $5 million in 2013, offset in 2014 by $2 million of insurance proceeds.

Our transportation and storage business segment depreciation and amortization increased $19 million primarily due to the additional assets in service from the acquisition of Enogex of $16 million, MRT rate case impact of $1 million and asset additions of $2 million.

Our transportation and storage business segment taxes other than income tax decreased $1 million due to reduced ad valorem taxes of $4 million, partially offset by the acquisition of Enogex, which contributed $3 million to taxes other than income tax.

Our transportation and storage business segment recorded equity in earnings of equity method affiliates of $12 million for the nine months ended September 30, 2014 and 2013, respectively, from our interest in SESH, a jointly owned pipeline.

Table of Contents

Condensed Combined and Consolidated Interim Information



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In millions)
Operating Income	$	152		$	115		$	452		$	339
Other Income (Expense):
Interest expense	(20		)	(13		)	(50		)	(53		)
Equity in earnings of equity method affiliates	5			3			12			12
Interest income—affiliated companies	—			1			—			9
Other, net	3			—			(2		)	—
Total Other Income (Expense)	(12		)	(9		)	(40		)	(32		)
Income Before Income Taxes	140			106			412			307
Income tax expense (benefit)	1			1			2			(1,195		)
Net Income	$	139		$	105		$	410		$	1,502
Less: Net income attributable to noncontrolling interest	—			1			2			2
Net Income attributable to Enable Midstream Partners, LP	$	139		$	104		$	408		$	1,500



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(In millions)
Other Financial Data:
Gross Margin ⁽¹⁾	$	364	$	333	$	1,082	$	838
Adjusted EBITDA ⁽¹⁾	231		205		670		529
Distributable cash flow ⁽¹⁾	161		134		503		361

_____________________


(1)	Gross margin, Adjusted EBITDA and distributable cash flow are defined and reconciled to their most directly comparable financial measures calculated and presented below under the caption Non-GAAP Financial Measure within this Part I, Item 2.

Three Months Ended September 30, 2014 compared to Three Months Ended September 30, 2013

Net Income attributable to the Partnership. We reported net income attributable to the Partnership of $139 million and $104 million in the three months ended September 30, 2014 and 2013, respectively. The increase in net income attributable to the Partnership of $35 million was primarily attributable to an increase in operating income of $37 million, an increase in other income and expense of $3 million, an increase in equity earnings in equity method affiliates of $2 million (discussed by business segment above), partially offset by a decrease in interest income of $1 million as a result of the reduction in notes receivable, and an increase in interest expense of $7 million in the three months ended September 30, 2014.

Interest Expense. Interest expense increased $7 million primarily due to higher interest rates associated with the Partnership's 2019 Notes, 2024 Notes and 2044 Notes issued in May 2014, as compared to the interest rates associated with the Partnership's Term Loan Facility that the 2019 Notes, 2024 Notes and 2044 Notes were used to repay.

Income Tax Expense. Effective May 1, 2013, upon conversion to a limited partnership, the Partnership’s earnings are no longer subject to income taxes (other Texas state margin taxes). Consequently, the Condensed Combined and Consolidated Statement of Income for the three months ended September 30, 2014 does not include an income tax provision (other than Texas state margin taxes and taxes associated with our corporate subsidiary).

Nine Months Ended September 30, 2014 compared to Nine Months Ended September 30, 2013

Net Income attributable to the Partnership. We reported net income attributable to the Partnership of $408 million and $1,500 million in the nine months ended September 30, 2014 and 2013, respectively. The decrease in net income attributable to the Partnership of $1,092 million was primarily attributable to the decrease in income tax benefit from no longer being subject to

Table of Contents

income taxes of $1,197 million, an increase in other income and expense of $2 million primarily related to the loss on extinguishment of debt, a decrease in interest income of $9 million as a result of the reduction in notes receivable, partially offset by a decrease in interest expense of $13 million (excluding the impact of interest on debt acquired with Enogex reflected in the acquisition impact below), an increase related to the acquisition of Enogex on May 1, 2013 of $50 million, and an increase in operating income of $53 million (excluding the impact of the acquisition of Enogex and discussed by business segment above) in the nine months ended September 30, 2014.

Interest Expense. Interest expense decreased $3 million, primarily due to a decrease of $13 million related to lower interest rates on the Partnership's outstanding debt (excluding the impact of the acquisition of Enogex discussed above), partially offset by a $10 million increase in interest expense incurred on the debt assumed with the acquisition of Enogex.

Income Tax Expense. Effective May 1, 2013, upon conversion to a limited partnership, the Partnership’s earnings are no longer subject to income taxes (other Texas state margin taxes). As a result of the conversion to a partnership, we recognized our outstanding current income tax liabilities and deferred income tax assets and liabilities by recording an income tax benefit of $1,197 million. Consequently, the Condensed Combined and Consolidated Statement of Income for the nine months ended September 30, 2014 does not include an income tax provision (other than Texas state margin taxes and taxes associated with our corporate subsidiary).

Non-GAAP Financial Measures

The Partnership has included the non-GAAP financial measures gross margin, Adjusted EBITDA and distributable cash flow in this report based on information in its condensed combined and consolidated financial statements.

Gross margin, Adjusted EBITDA and distributable cash flow are supplemental financial measures that management and external users of the Partnership’s financial statements, such as industry analysts, investors, lenders and rating agencies may use, to assess:


•	The Partnership’s operating performance as compared to those of other publicly traded partnerships in the midstream energy industry, without regard to capital structure or historical cost basis;


•	The ability of the Partnership’s assets to generate sufficient cash flow to make distributions to its partners;


•	The Partnership’s ability to incur and service debt and fund capital expenditures; and


•	The viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

This report includes a reconciliation of gross margin to revenues, Adjusted EBITDA and distributable cash flow to net income attributable to controlling interest, and Adjusted EBITDA to net cash provided by operating activities, the most directly comparable GAAP financial measures, on a historical basis, as applicable, for each of the periods indicated. The Partnership believes that the presentation of gross margin, Adjusted EBITDA and distributable cash flow provides information useful to investors in assessing its financial condition and results of operations. Gross margin, Adjusted EBITDA and distributable cash flow should not be considered as alternatives to net income, operating income, revenue, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Gross margin, Adjusted EBITDA and distributable cash flow have important limitations as an analytical tool because they exclude some but not all items that affect the most directly comparable GAAP measures. Additionally, because gross margin, Adjusted EBITDA and distributable cash flow may be defined differently by other companies in the Partnership’s industry, its definitions of gross margin, Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(In millions)
Reconciliation of Gross Margin to Revenue:
Revenues	$	803	$	792	$	2,632	$	1,665
Cost of goods sold, excluding depreciation and amortization	439		459		1,550		827
Gross margin	$	364	$	333	$	1,082	$	838

Table of Contents




Reconciliation of Adjusted EBITDA and distributable cash flow to net income attributable to controlling interest:
Net income attributable to Enable Midstream Partners, LP	$	139		$	104		$	408		$	1,500
Add:
Depreciation and amortization expense	69			67			205			148
Interest expense, net of interest income	20			12			50			44
Income tax expense (benefit)	1			1			2			(1,195		)
EBITDA	$	229		$	184		$	665		$	497
Add:
Loss on extinguishment of debt	—			—			4			—
Distributions from equity method affiliates ⁽¹⁾	7			3			13			20
Other non-cash losses	8			9			8			12
Impairment	1			12			1			12
Less:
Other non-cash gains	(9		)	—			(9		)	—
Equity in earnings of equity method affiliates	(5		)	(3		)	(12		)	(12		)
Adjusted EBITDA	$	231		$	205		$	670		$	529
Less:
Adjusted interest expense, net ⁽²⁾	(23		)	(17		)	(60		)	(51		)
Maintenance capital expenditures	(47		)	(54		)	(107		)	(117		)
Distributable cash flow	$	161		$	134		$	503		$	361

Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities	$	269		$	184		$	561		$	472
Interest expense, net of interest income	20			12			50			44
Net income attributable to noncontrolling interest	—			(1		)	(2		)	(2		)
Income tax expense (benefit)	1			1			2			(1,195		)
Deferred income tax benefit	—			2			1			1,197
Equity in earnings of equity method affiliates, net of distributions ⁽¹⁾	(2		)	—			(1		)	(8		)
Impairment	(1		)	(12		)	(1		)	(12		)
Other non-cash items	(5		)	(1		)	(11		)	(2		)
Changes in operating working capital which (provided) used cash:
Accounts receivable	(20		)	21			11			39
Accounts payable	(5		)	(19		)	96			(10		)
Other, including changes in noncurrent assets and liabilities	(28		)	(3		)	(41		)	(26		)
EBITDA	$	229		$	184		$	665		$	497
Add:
Loss on extinguishment of debt	—			—			4			—
Distributions from equity method affiliates ⁽¹⁾	7			3			13			20
Impairment	1			12			1			12
Other non-recurring losses	8			9			8			12
Less:
Other non-recurring gains	(9		)	—			(9		)	—
Equity in earnings of equity method affiliates	(5		)	(3		)	(12		)	(12		)
Adjusted EBITDA	$	231		$	205		$	670		$	529

Table of Contents

____________________

(1) Excludes $198 million in special distributions for the return of investment in SESH for the nine month period ended September 30, 2014.

(2) Adjusted interest expense, net excludes the effect of the amortization of the premium on Enogex’s fixed rate senior notes. This exclusion is the primary reason for the difference between “Interest expense, net” and “Adjusted interest expense, net.”

Liquidity and Capital Resources

Capital Requirements

The midstream business is capital intensive and can require significant investment to maintain and upgrade existing operations, connect new wells to the system, organically grow into new areas and comply with environmental and safety regulations. Going forward, our capital requirements will consist of the following:


•	maintenance capital expenditures, which are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long-term, our operating capacity or operating income; and


•	expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.

Our future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available to us. We expect to fund future capital expenditures from cash flow generated from our operations, borrowings under our revolving credit facility, the issuance of commercial paper or new debt offerings or the issuance of additional partnership units.

Distributions

On October 24, 2014, the board of directors of Enable GP declared a quarterly cash distribution of $0.3025 per common unit on all of the Partnership's outstanding common and subordinated units for the period ended September 30, 2014. The distribution will be paid November 14, 2014 to unit holders of record as of the close of business November 4, 2014. This distribution is based on the Partnership’s Second Amended and Restated Agreement of Limited Partnership, which went into effect on April 16, 2014.

Issuance of Long-Term Debt

On May 27, 2014, the Partnership completed the private offering of 2019 Notes, 2024 Notes and 2044 Notes, with registration rights. The Partnership received aggregate proceeds of $1.63 billion. Certain of the proceeds were used to repay the Term Loan Facility, and certain of the proceeds were used to repay the Enable Oklahoma $250 million variable rate term loan and the Enable Oklahoma $200 million 6.875% senior notes due July 15, 2014, and for general corporate purposes. See Note 16 for discussion of the repayment of the Enable Oklahoma $200 million 6.875% senior notes. A wholly owned subsidiary of CenterPoint Energy has guaranteed collection of the Partnership’s obligations under the 2019 Notes and 2024 Notes, on an unsecured subordinated basis, subject to automatic release on May 1, 2016.

Working Capital

Working capital is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from, customers, and the level and timing of spending for maintenance and expansion activity. As of September 30, 2014, we had working capital of $1 million. We utilize the Revolving Credit Facility to manage the timing of cash flows and fund short-term working capital deficits.

Table of Contents

Cash Flows

The following tables reflect cash flows for the applicable periods:



	Nine Months Ended September 30,
	2014			2013
	(In millions)
Net cash provided by operating activities	$	561		$	472
Net cash (used in) provided by investing activities	(573		)	63
Net cash provided by (used in) financing activities	(78		)	(511		)

Operating Activities

There was an increase of $89 million in net cash provided by operating activities for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013 due to the impact of timing of payments and receipts on changes in assets and liabilities partially offset by:


•	the acquisition of Enogex on May 1, 2013, which added $186 million in gross margin and $70 million in operation and maintenance expenses during the nine months ended September 30, 2014; and


•	excluding the acquisition of Enogex:


•	higher Gathering and Processing gross margin of $32 million;


•	higher Transportation and Storage gross margin of $26 million; and


•	higher payroll related expenses of $19 million and higher non-capital costs of $7 million, offset by lower integration costs of $7 million and other costs of $9 million, all within operation and maintenance expenses.

Investing Activities

The increase of $636 million in net cash used in investing activities for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013 was primarily due to higher gathering and processing capital expenditures of $253 million, the payment of the notes receivable—affiliated companies of $434 million in 2013, and investment in equity method affiliates of $187 million, partially offset by lower transportation and storage capital expenditures of $33 million, and distributions from equity method affiliates of $198 million in 2014.

Financing Activities

The Partnership also has a $1.4 billion Revolving Credit Facility, discussed in Note 8 of the condensed combined and consolidated financial statements and related notes. During the nine months ended September 30, 2014, there were gross borrowings under the Revolving Credit Facility of $115 million and gross repayments of $487 million. As of September 30, 2014, there were no principal advances and $2 million in letters of credit outstanding under the Revolving Credit Facility. Commercial paper borrowings effectively reduce our borrowing capacity under this Revolving Credit Facility. As of September 30, 2014, we had $95 million outstanding under our commercial paper program. On May 27, 2014, the Partnership completed the private offering of $1.65 billion of our 2019 Notes, 2024 Notes and 2044 Notes. See Note 8 for further discussion.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Credit Risk

We are exposed to certain credit risks relating to our ongoing business operations. Credit risk includes the risk that counterparties that owe us money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected, and we could incur losses. We examine the creditworthiness of third party customers to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees.

Table of Contents

Critical Accounting Policies and Estimates

As of September 30, 2014, there have been no significant changes to our critical accounting policies and estimates as disclosed in our Prospectus.

Supplemental Disclosures

Certain information contained in this report relates to periods that began prior to the acquisition of Enogex by Enable Midstream Partners, LP. The Partnership believes that combined historical data with Enogex, along with certain pro forma adjustments, is relevant and meaningful, enhances the discussion of periods presented and is useful to the reader to better understand trends in the Partnership's operations. The pro forma adjustments, as discussed in the footnotes below, only give effect to events that are (1) directly attributable to the formation of the Partnership; (2) factually supportable; and (3) expected to have a continuing effect on the consolidated results of the Partnership.

The following information is for informational purposes only and should not be considered indicative of future results. The following pro forma financial data was derived from the Partnership's combined financial information, Enogex consolidated financial information and certain adjustments described below. Further, management does not believe that the pro forma financial data is necessarily indicative of the financial data that would have been reported by the Partnership had the acquisition of Enogex closed prior to the historical period presented, future results of the Partnership, or other transactions that resulted in the formation of the Partnership.

Table of Contents

UNAUDITED SUPPLEMENTAL PRO FORMA CONDENSED COMBINED STATEMENT OF INCOME

For the nine months ended September 30, 2013



	Enable Midstream Partners, LP Historical			Enogex Historical			Pro Forma Adjustments				Pro Forma
	(In millions)
Revenues	$	1,665		$	630		$	1		^A	$	2,296
Cost of goods sold, excluding depreciation and amortization	827			489			(4		)	^A	1,312
Operating Expenses:
Operation and maintenance	302			64			—				366
Depreciation and amortization	148			37			20			^A	205
Impairment	12			—			—				12
Taxes other than income tax	37			8			—				45
Total Operating Expenses	499			109			20				628
Operating income	339			32			(15		)		356
Other Income (Expense):
Interest expense	(53		)	(10		)	31			^B	(35		)
							2			^B
							(7		)	^C
							(1		)	^D
							3			^A
Equity in earnings of equity method affiliates	12			—			(3		)	^F	9
Interest income—affiliated companies	9			—			(9		)	^B	—
Other, net	—			9			—				9
Total Other Income (Expense)	(32		)	(1		)	16				(17		)
Income Before Income Taxes	307			31			1				339
Income tax expense (benefit)	(1,195		)	—			1,196			^E	1
Net Income	1,502			31			(1,195		)		338
Less: Net income attributable to noncontrolling interest	2			—			—				2
Net Income attributable to Enable Midstream Partners, LP	$	1,500		$	31		$	(1,195	)		$	336

(A) This adjustment reflects the acquisition of Enogex on May 1, 2013:

Revenue. The impact of removing the historical amortization and the historical recognition of deferred revenues at May 1, 2013 results in a net increase to revenue of $1 million during the nine months ended September 30, 2013.

Cost of Goods Sold, Excluding Depreciation and Amortization. The impact of recognizing liabilities for Enogex loss contracts at May 1, 2013 results in a reduction to cost of goods sold, excluding depreciation and amortization, of $4 million during the nine months ended September 30, 2013.

Depreciation and Amortization. As a result of applying purchase accounting to the acquisition of Enogex, property, plant and equipment and identifiable intangible assets were recorded at their fair value, resulting in additional depreciation and amortization expense. The impact of the step-up on depreciation expense is $20 million during the nine months ended September 30, 2013.

Interest Expense. The pro forma impact of the amortization of the premium, less the historical recognition of the premium, discount and deferred charges on interest expense, net of historical capitalized interest, is $3 million during the nine months ended September 30, 2013.

Table of Contents

(B) Interest Expense. This adjustment reflects the settlement on May 1, 2013 of certain notes receivable—affiliated companies and notes payable—affiliated companies with CenterPoint Energy and OGE Energy, historically held by the Partnership and Enogex, respectively, by a total of $24 million during the nine months ended September 30, 2013.

(C) Interest Expense. This adjustment reflects the entrance into the $1.05 billion Term Loan Facility on May 1, 2013: this issuance results in an increase in interest expense of $7 million during the nine months ended September 30, 2013.

(D) Interest Expense. This adjustment reflects the entrance into the Revolving Credit Facility on May 1, 2013: this issuance results in an increase in interest expense of $1 million during the nine months ended September 30, 2013.

(E) Income Tax Expense. Upon conversion to a limited partnership on May 1, 2013, the Partnership’s earnings are no longer subject to income tax (other than Texas state margin taxes) and are taxable at the individual partner level. The pro forma adjustment to income taxes for the nine months ended September 30, 2013 removes $1.2 billion of historical income tax benefit.

(F) Equity in earnings of equity method affiliates. The 25.05% interest in SESH distributed to CenterPoint Energy results in a pro forma reduction to earnings of equity method affiliates of $3 million during the nine months ended September 30, 2013.



	Nine Months Ended September 30,
	Historical	Pro Forma
	2014	2013
Operating Data:
Gathered volumes—TBtu	913	975
Gathered volumes—TBtu/d	3.34	3.56
Natural gas processed volumes—TBtu	418	392
Natural gas processed volumes—TBtu/d	1.53	1.43
NGLs produced - MBbl/d⁽¹⁾	67.63	58.88
NGLs sold—MBbl/d⁽¹⁾⁽³⁾	69.60	59.11
Condensate sold - MBbl/d	4.31	2.91
Crude Oil - Gathered volumes - MBbl/d⁽²⁾	2.37	—
Transported volumes—TBtu	1,373	1,378
Transportation volumes—TBtu/d	5.02	5.04
Interstate firm contracted capacity—Bcf/d	8.69	7.74
Intrastate average deliveries - TBtu/day	1.62	1.59

_____________________


(1)	Excludes condensate.


(2)	Initial operation of our crude oil gathering system began on November 1, 2013.


(3)	NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.

Table of Contents



	Nine Months Ended September 30,
	Historical			Pro Forma
	2014			2013
	(In millions)
Reconciliation of Gross Margin to Revenue:
Revenues	$	2,632		$	2,296
Cost of goods sold, excluding depreciation and amortization	1,550			1,312
Gross margin	$	1,082		$	984
Reconciliation of Adjusted EBITDA and distributable cash flow to net income attributable to controlling interest:
Net income attributable to Enable Midstream Partners, LP	$	408		$	336
Add:
Depreciation and amortization expense	205			205
Interest expense, net of interest income	50			35
Income tax expense (benefit)	2			1
EBITDA	$	665		$	577
Add:
Loss on extinguishment of debt	4			—
Distributions from equity method affiliates⁽¹⁾	13			16
Impairment	1			12
Other non-cash losses	8			16
Less:
Equity in earnings of equity method affiliates	(12		)	(9		)
Other non-cash gains	(9		)	—
Gain on disposition	—			(10		)
Adjusted EBITDA	$	670		$	602
Less:
Adjusted interest expense, net ⁽²⁾	(60		)	(44		)
Maintenance capital expenditures	(107		)	(127		)
Distributable cash flow	$	503		$	431

_____________________


(1)	Excludes $198 million in distributions of investment in equity method affiliates for the nine month period ended September 30, 2014.


(2)	Adjusted interest expense, net excludes the effect of the amortization of the premium on Enogex’s fixed rate senior notes. This exclusion is the primary reason for the difference between “Interest expense, net” and “Adjusted interest expense, net.”

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to various market risks, including volatility in commodity prices and interest rates.

Commodity Price Risk

While we generate a substantial portion of our gross margin pursuant to long-term, fee-based contracts that include minimum volume commitments and/or demand fees, we are also exposed to changes in the prices for natural gas and NGLs at various market hubs. To manage our direct exposure to commodity prices we have historically used forward commodity sales and other derivative contracts. We do not enter into risk management contracts for speculative purposes.

Table of Contents

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness associated with our Revolving Credit Facility and the refinancing of our existing term loans. The credit markets have recently experienced historical lows in interest rates. It is possible that interest rates could continue to rise from these low levels in the future, which would cause our financing costs on floating rate credit facilities and future debt offerings to be higher than current levels.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of September 30, 2014. Based on such evaluation, our management has concluded that, as of September 30, 2014, our disclosure controls and procedures are designed and effective to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms and that information is accumulated and communicated to our management, including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that our controls will succeed in achieving their goals under all potential future conditions.

Changes in Internal Controls

There were no changes in our internal controls over financial reporting during the quarter ended September 30, 2014, that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.

Internal Control Over Financial Reporting

The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules that generally require every company that files reports with the SEC to include a management report on such company's internal control over financial reporting in its annual report. In addition, our independent registered public accounting firm must attest to our internal control over financial reporting. Our first Annual Report on Form 10-K will not include a report of management's assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by SEC rules applicable to new public companies. Management will be required to provide an assessment of effectiveness of our internal control over financial reporting in our Annual Report on Form 10-K for the year ended December 31, 2015. We are required to comply with the auditor attestation requirement of Section 404 of the Sarbanes-Oxley Act in our Annual Report on Form 10-K for the year ended December 31, 2015.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Information regarding legal proceedings is set forth in Note (12) - Commitments and Contingencies to the Partnership's condensed combined and consolidated financial statements included in Item 1 of Part I of this Quarterly Report on Form 10-Q and is incorporated herein by reference.

Table of Contents

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. Risk factors relating to the Partnership are set forth under "Risk Factors" in our Prospectus. No material changes to such risk factors have occurred during the three and nine months ended September 30, 2014.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

On April 10, 2014, the Partnership priced the Offering of 25,000,000 common units at a price to the public of $20.00 per common unit. The Offering was made pursuant to a registration statement on Form S-1, as amended (File No. 333-192542) that was declared effective by the SEC on April 10, 2014. The selling unitholder also granted the underwriters an option for a period of 30 days to purchase up to an additional 3,750,000 common units on the same terms. On April 11, 2014, the underwriters exercised the option in full, 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. Morgan Stanley, Barclays, Goldman, Sachs & Co., Citigroup, Deutsche Bank Securities, J.P. Morgan, UBS Investment Bank and Wells Fargo Securities acted as joint book-running managers for the Offering, and BofA Merrill Lynch, Credit Suisse and RBC Capital Markets acted as co-managers for the Offering.

The Offering closed on April 16, 2014. The Partnership received net proceeds from the sale of the common units of approximately $464 million, after deducting underwriting discounts and commissions of approximately $29 million, and the structuring fee and offering expenses of approximately $7 million. The Partnership retained approximately $451 million of the net proceeds of the Offering for general partnership purposes, including the funding of expansion capital expenditures, and approximately $13 million to pre-fund demand fees expected to be incurred over the next three years relating to certain expiring transportation and storage contracts. As of September 30, 2014, $451 million has been spent for the repayment of debt and expansion capital expenditures.

Prior to May 30, 2014, the Partnership owned a 24.95% interest in SESH, and CenterPoint Energy indirectly owned a 25.05% interest in SESH. On May 13, 2014, CenterPoint Energy exercised a put right with respect to a 24.95% interest in SESH. Pursuant to the put right, on May 30, 2014, CenterPoint Energy contributed its 24.95% interest in SESH to the Partnership in exchange for 6,322,457 common units representing limited partner interests in the Partnership.

Item 6. Exhibits

The following exhibits are filed herewith:

Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated by reference to a prior filing as indicated.

Agreements included as exhibits are included only to provide information to investors regarding their terms. Agreements listed below may contain representations, warranties and other provisions that were made, among other things, to provide the parties thereto with specified rights and obligations and to allocate risk among them, and no such agreement should be relied upon as constituting or providing any factual disclosures about Enable Midstream Partners, LP, any other persons, any state of affairs or other matters.

Table of Contents



Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
2.1	Master Formation Agreement dated as of March 14, 2013 by and among CenterPoint Energy, Inc., OGE Energy Corp., Bronco Midstream Holdings, LLC and Bronco Midstream Holdings II, LLC	Registrant’s registration statement on Form S-1, filed on November 26, 2013	File No. 333-192545	Exhibit 2.1
3.1	Certificate of Limited Partnership of CenterPoint Energy Field Services LP, as amended	Registrant’s registration statement on Form S-1, filed on November 26, 2013	File No. 333-192545	Exhibit 3.1
3.2	Second Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP	Registrant's Form 8-K filed April 22,2014	File No. 1-36413	Exhibit 3.1
4.1	Specimen Unit Certificate representing common units (included with Second Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP as Exhibit A thereto)	Registrant's Form 8-K filed April 22,2014	File No. 1-36413	Exhibit 3.1
4.2	Indenture, dated as of May 27, 2014, between Enable Midstream Partners, LP and U.S. Bank National Association, as trustee.	Registrant’s Form 8-K filed May 29, 2014	File No. 001-36413	Exhibit 4.1
4.3	First Supplemental Indenture, dated as of May 27, 2014, by and among Enable Midstream Partners, LP, CenterPoint Energy Resources Corp., as guarantor, and U.S. Bank National Association, as trustee.	Registrant’s Form 8-K filed May 29, 2014	File No. 001-36413	Exhibit 4.2
4.4	Registration Rights Agreement, dated as of May 27, 2014, by and among Enable Midstream Partners, LP, 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.	Registrant’s Form 8-K filed May 29, 2014	File No. 001-36413	Exhibit 4.3
+10.1	First Amendment to Employee Transition Agreement, dated as of October 22, 2014 by and among Enable GP, LLC, CenterPoint Energy, Inc. and OGE Energy Corp
+10.2	First Amendment to OGE Transitional Seconding Agreement, dated as of October 22, 2014, between OGE Energy Corp. and Enable Midstream Partners, LP
+10.3	First Amendment to Services Agreement, dated as of October 22, 2014, between OGE Energy Corp and Enable Midstream Partners, LP
+31.1	Rule 13a-14(a)/15d-14(a) Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
+31.2	Rule 13a-14(a)/15d-14(a) Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
+32.1	Section 1350 Certification of principal executive officer
+32.2	Section 1350 Certification of principal financial officer
+101.INS	XBRL Instance Document.
+101.SCH	XBRL Taxonomy Schema Document.
+101.PRE	XBRL Taxonomy Presentation Linkbase Document.
+101.LAB	XBRL Taxonomy Label Linkbase Document.
+101.CAL	XBRL Taxonomy Calculation Linkbase Document.
+101.DEF	XBRL Definition Linkbase Document.

Table of Contents

SIGNATURE

Pursuant to the requirements of the Securities Act of 1934, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized.



		ENABLE MIDSTREAM PARTNERS, LP
		(Registrant)

		By: ENABLE GP, LLC
		Its general partner

Date:	November 4, 2014	By:	/s/ Tom Levescy
			Tom Levescy
			Senior Vice President, Chief Accounting Officer and Controller
			(Principal Accounting Officer)