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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

_______________________________________

FORM 10-Q

_______________________________________



☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended	September 30, 2019



☐	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

https://cdn.kscope.io/379d74d240fa346af1e9e2bbf2638a68-enablernotagrgba01.jpg

ENABLE MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)

_______________________________________



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

499 West Sheridan Avenue,	Suite 1500	Oklahoma City,	Oklahoma	73102
(Address of Principal Executive Offices)				(Zip Code)

(405) 525-7788

Registrant’s telephone number, including area code

_______________________________________

Securities registered pursuant to Section 12(b) of the Act:

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. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ☒ No ☐

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



Large accelerated filer	☒	Accelerated filer	☐

Non-accelerated filer	☐	Smaller reporting company	☐

		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) 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 ☐ No ☒

As of October 14, 2019, there were 435,152,510 common 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 Consolidated Statements of Income	4
Condensed Consolidated Statements of Comprehensive Income	5
Condensed Consolidated Balance Sheets	6
Condensed Consolidated Statements of Cash Flows	7
Condensed Consolidated Statements of Partners' Equity	8
Notes to Condensed Consolidated Financial Statements	9
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3. Quantitative and Qualitative Disclosures About Market Risk	51
Item 4. Controls and Procedures	52

Part II - OTHER INFORMATION
Item 1. Legal Proceedings	53
Item 1A. Risk Factors	53
Item 6. Exhibits	53

Signature	55

AVAILABLE INFORMATION

Our website is www.enablemidstream.com. On the investor relations tab of our website, http://investors.enablemidstream.com, we make available free of charge a variety of information to investors. Our goal is to maintain the investor relations tab of our website as a portal through which investors can easily find or navigate to pertinent information about us, including but not limited to:


•	our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after we electronically file that material with or furnish it to the SEC;


•	press releases on quarterly distributions, quarterly earnings, and other developments;


•	governance information, including our governance guidelines, committee charters, and code of ethics and business conduct;


•	information on events and presentations, including an archive of available calls, webcasts, and presentations;


•	news and other announcements that we may post from time to time that investors may find useful or interesting; and


•	opportunities to sign up for email alerts and RSS feeds to have information pushed in real time.

Information contained on our website or any other website is not incorporated by reference into this report and does not constitute a part of this report.

Table of Contents

GLOSSARY OF TERMS



2019 Notes.	$500 million aggregate principal amount of the Partnership’s 2.400% senior notes due 2019.
2019 Term Loan Agreement.	Unsecured term loan agreement dated January 29, 2019, by and among Enable Midstream Partners, LP and Bank of America, N.A., as administrative agent, and the several lenders from time to time party thereto.
2024 Notes.	$600 million aggregate principal amount of the Partnership’s 3.900% senior notes due 2024.
2027 Notes.	$700 million aggregate principal amount of the Partnership’s 4.400% senior notes due 2027.
2028 Notes.	$800 million aggregate principal amount of the Partnership’s 4.950% senior notes due 2028.
2029 Notes.	$550 million aggregate principal amount of the Partnership’s 4.150% senior notes due 2029.
2044 Notes.	$550 million aggregate principal amount of the Partnership’s 5.000% senior notes due 2044.
Adjusted EBITDA.	A non-GAAP measure calculated as net income attributable to limited partners plus depreciation and amortization expense, interest expense, net of interest income, income tax expense, distributions received from equity method affiliate in excess of equity earnings, non-cash equity-based compensation, change in fair value of derivatives not designated as hedging instruments, certain other non-cash gains and losses (including gains and losses on sales of assets and write-downs of materials and supplies) and impairments, less the noncontrolling interest allocable to Adjusted EBITDA.
Adjusted interest expense.	A non-GAAP measure calculated as interest expense plus interest income, amortization of premium on long-term debt and capitalized interest on expansion capital, less amortization of debt costs and discount on long-term debt.
Annual Report.	Annual Report on Form 10-K for the year ended December 31, 2018.
ASC.	Accounting Standards Codification.
ASU.	Accounting Standards Update.
Atoka.	Atoka Midstream LLC, in which the Partnership owns a 50% interest, which provides gathering and processing services to customers in the Arkoma Basin in Oklahoma.
ATM Program.	The offer and sale, from time to time, of common units representing limited partner interest having an aggregate offering price of up to $200 million in quantities, by sales methods and at prices determined by market conditions and other factors at the time of such sales, pursuant to that certain ATM Equity Offering Sales Agreement, entered into on May 12, 2017.
Barrel.	42 U.S. gallons of petroleum products.
Bbl.	Barrel.
Bbl/d.	Barrels per day.
Bcf/d.	Billion cubic feet per day.
Board of Directors.	The board of directors of Enable GP, LLC.
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.
Condensate.	A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
DCF.	Distributable Cash Flow, a non-GAAP measure calculated as Adjusted EBITDA, as further adjusted for Series A Preferred Unit distributions, distributions for phantom and performance units, Adjusted interest expense, maintenance capital expenditures and current income taxes.
Distribution coverage ratio.	A non-GAAP measure calculated as DCF divided by distributions related to common unitholders.
EGR	Enable Gulf Run Transmission, LLC, a Delaware limited liability company, a wholly owned subsidiary of the Partnership.
EGT.	Enable Gas Transmission, LLC, a wholly owned subsidiary of the Partnership that operates an approximately 5,900-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.

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EOCS.	Enable Oklahoma Crude Services, LLC, formerly Velocity Holdings, LLC, a wholly owned subsidiary of the Partnership that provides crude oil and condensate gathering services in the SCOOP and STACK plays of the Anadarko Basin in Oklahoma.
EOIT.	Enable Oklahoma Intrastate Transmission, LLC, formerly Enogex LLC, a wholly owned subsidiary of the Partnership that operates an approximately 2,300-mile intrastate pipeline that provides natural gas transportation and storage services to customers in Oklahoma.
EOIT Senior Notes.	$250 million 6.25% senior notes due 2020.
ESCP.	Enable South Central Pipeline, LLC, formerly Velocity Pipeline Partners, LLC, a Delaware limited liability company, in which the Partnership, through EOCS, owns a 60% joint venture interest in a 26-mile pipeline system with a third party which owns and operates a refinery connected to the EOCS system.
Exchange Act.	Securities Exchange Act of 1934, as amended.
FASB.	Financial Accounting Standards Board.
FERC.	Federal Energy Regulatory Commission.
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.	A non-GAAP measure calculated as Total revenues minus Cost of natural gas and natural gas liquids, excluding depreciation and amortization.
ICE.	Intercontinental Exchange.
LDC.	Local distribution company involved in the delivery of natural gas to consumers within a specific geographic area.
LIBOR.	London Interbank Offered Rate.
MBbl.	Thousand barrels.
MBbl/d.	Thousand barrels per day.
MMcf.	Million cubic feet of natural gas.
MMcf/d.	Million cubic feet per day.
Moody’s.	Moody’s Investor Services.
MRT.	Enable Mississippi River Transmission, LLC, a wholly owned subsidiary of the Partnership that operates a 1,600-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.
OGE Energy.	OGE Energy Corp., an Oklahoma corporation, and its subsidiaries.
Partnership.	Enable Midstream Partners, LP, and its subsidiaries.
Partnership Agreement.	Fifth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP dated as of November 14, 2017.
PHMSA.	Pipeline and Hazardous Materials Safety Administration.
Revolving Credit Facility.	$1.75 billion senior unsecured revolving credit facility.
S&P.	Standard & Poor’s Rating Services.
SCOOP.	South Central Oklahoma Oil Province.
SEC.	Securities and Exchange Commission.
Series A Preferred Units.	10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in the Partnership.
SESH.	Southeast Supply Header, LLC, in which the Partnership owns a 50% interest, that operates an approximately 290-mile interstate natural gas pipeline from Perryville, Louisiana to southwestern Alabama near the Gulf Coast.
STACK.	Sooner Trend (oil field), Anadarko (basin), Canadian and Kingfisher (counties).
TBtu.	Trillion British thermal units.
TBtu/d.	Trillion British thermal units per day.
WTI.	West Texas Intermediate.

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FORWARD-LOOKING STATEMENTS

Some of the information in this report may contain forward-looking statements. 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 our Annual Report. Those risk factors and other factors noted throughout this report and in our Annual Report 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 supply and 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;


•	strategic decisions by CenterPoint Energy and OGE Energy regarding their ownership of us and Enable GP;


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


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


•	interest rates;


•	the timing and extent of changes in labor and material prices;


•	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 current or future litigation; and


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

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 CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018

	(In millions, except per unit data)
Revenues (including revenues from affiliates (Note 13)):
Product sales	$	320		$	553		$	1,156		$	1,497
Service revenues	379			375			1,073			984
Total Revenues	699			928			2,229			2,481
Cost and Expenses (including expenses from affiliates (Note 13)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	263			516			958			1,335
Operation and maintenance	105			98			307			289
General and administrative	31			28			82			81
Depreciation and amortization	108			100			323			292
Taxes other than income tax	17			15			52			48
Total Cost and Expenses	524			757			1,722			2,045
Operating Income	175			171			507			436
Other Income (Expense):
Interest expense	(48		)	(40		)	(142		)	(109		)
Equity in earnings of equity method affiliate	5			7			12			20
Other, net	1			1			2			1
Total Other Expense	(42		)	(32		)	(128		)	(88		)
Income Before Income Tax	133			139			379			348
Income tax benefit	—			—			(1		)	—
Net Income	$	133		$	139		$	380		$	348
Less: Net income attributable to noncontrolling interest	1			1			2			1
Net Income Attributable to Limited Partners	$	132		$	138		$	378		$	347
Less: Series A Preferred Unit distributions (Note 7)	9			9			27			27
Net Income Attributable to Common Units (Note 6)	$	123		$	129		$	351		$	320

Basic earnings per unit (Note 6)
Common units	$	0.28		$	0.30		$	0.81		$	0.74
Diluted earnings per unit (Note 6)
Common units	$	0.28		$	0.30		$	0.81		$	0.73

See Notes to the Unaudited Condensed Consolidated Financial Statements

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ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,					Nine Months Ended September 30,
	2019			2018		2019			2018

	(In millions)
Net income	$	133		$	139	$	380		$	348
Other comprehensive loss:
Unrealized losses on derivative instruments	(1		)	—		(4		)	—
Reclassification of derivative losses to net income	—			—		—			—
Other comprehensive loss	(1		)	—		(4		)	—
Comprehensive income	132			139		376			348
Less: Comprehensive income attributable to noncontrolling interest	1			1		2			1
Comprehensive income attributable to Limited Partners	$	131		$	138	$	374		$	347

Table of Contents

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2019			December 31, 2018

	(In millions)
Current Assets:
Cash and cash equivalents	$	12		$	8
Restricted cash	1			14
Accounts receivable, net of allowance for doubtful accounts (Note 1)	268			290
Accounts receivable—affiliated companies	22			19
Inventory	47			50
Gas imbalances	23			29
Other current assets	44			39
Total current assets	417			449
Property, Plant and Equipment:
Property, plant and equipment	13,171			12,899
Less accumulated depreciation and amortization	2,263			2,028
Property, plant and equipment, net	10,908			10,871
Other Assets:
Intangible assets, net	616			663
Goodwill	98			98
Investment in equity method affiliate	309			317
Other	87			46
Total other assets	1,110			1,124
Total Assets	$	12,435		$	12,444
Current Liabilities:
Accounts payable	$	147		$	288
Accounts payable—affiliated companies	2			4
Current portion of long-term debt	253			500
Short-term debt	182			649
Taxes accrued	58			31
Gas imbalances	17			22
Other	160			121
Total current liabilities	819			1,615
Other Liabilities:
Accumulated deferred income taxes, net	5			5
Regulatory liabilities	24			23
Other	79			54
Total other liabilities	108			82
Long-Term Debt	3,968			3,129
Commitments and Contingencies (Note 14)
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at September 30, 2019 and December 31, 2018)	362			362
Common units (435,150,159 issued and outstanding at September 30, 2019 and 433,232,411 issued and outstanding at December 31, 2018, respectively)	7,145			7,218
Accumulated other comprehensive loss	(4		)	—
Noncontrolling interest	37			38
Total Partners’ Equity	7,540			7,618
Total Liabilities and Partners’ Equity	$	12,435		$	12,444

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ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
	2019			2018

	(In millions)
Cash Flows from Operating Activities:
Net income	$	380		$	348
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	323			292
Deferred income taxes	(1		)	—
Loss on sale/retirement of assets	5			1
Equity in earnings of equity method affiliate	(12		)	(20		)
Return on investment in equity method affiliate	12			20
Equity-based compensation	13			12
Amortization of debt costs and discount (premium)	(1		)	(1		)
Changes in other assets and liabilities:
Accounts receivable, net	19			(56		)
Accounts receivable—affiliated companies	(3		)	(2		)
Inventory	3			(5		)
Gas imbalance assets	6			12
Other current assets	(2		)	(19		)
Other assets	8			(6		)
Accounts payable	(108		)	(19		)
Accounts payable—affiliated companies	(2		)	—
Gas imbalance liabilities	(5		)	8
Other current liabilities	64			55
Other liabilities	(8		)	18
Net cash provided by operating activities	691			638
Cash Flows from Investing Activities:
Capital expenditures	(353		)	(551		)
Proceeds from sale of assets	1			8
Proceeds from insurance	—			1
Return of investment in equity method affiliate	8			11
Other, net	(9		)	—
Net cash used in investing activities	(353		)	(531		)
Cash Flows from Financing Activities:
(Decrease) increase in short-term debt	(467		)	8
Proceeds from long-term debt, net of issuance costs	1,544			787
Repayment of long-term debt	(700		)	(450		)
Repayment of Revolving Credit Facility	(250		)	—
Proceeds from issuance of common units, net of issuance costs	—			2
Distributions to common unitholders	(420		)	(413		)
Distributions to Series A Preferred Units	(27		)	(27		)
Distributions to non-controlling interests	(3		)	(2		)
Cash paid for employee equity-based compensation	(24		)	(9		)
Net cash used in financing activities	(347		)	(104		)
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash	(9		)	3
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	22			19
Cash, Cash Equivalents and Restricted Cash at End of Period	$	13		$	22

See Notes to the Unaudited Condensed Consolidated Financial Statements

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ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

(Unaudited)



	Nine Months Ended September 30, 2019
	Series A Preferred Units				Common Units				Accumulated Other Comprehensive Loss			Noncontrolling Interest			Total Partners’ Equity
	Units	Value			Units	Value			Value			Value			Value

	(In millions)
Balance as of December 31, 2018	15	$	362		433	$	7,218		$	—		$	38		$	7,618
Net income	—	9			—	113			—			1			123
Distributions	—	(9		)	—	(138		)	—			(1		)	(148		)
Equity-based compensation, net of units for employee taxes	—	—			2	(10		)	—			—			(10		)
Balance as of March 31, 2019	15	$	362		435	$	7,183		$	—		$	38		$	7,583
Net income	—	9			—	115			—			—			124
Other comprehensive loss	—	—			—	—			(3		)	—			(3		)
Distributions	—	(9		)	—	(138		)	—			(1		)	(148		)
Equity-based compensation, net of units for employee taxes	—	—			—	3			—			—			3
Balance as of June 30, 2019	15	$	362		435	$	7,163		$	(3	)	$	37		$	7,559
Net income	—	9			—	123			—			1			133
Other comprehensive loss	—	—			—	—			(1		)	—			(1		)
Distributions	—	(9		)	—	(144		)	—			(1		)	(154		)
Equity-based compensation, net of units for employee taxes	—	—			—	3			—			—			3
Balance as of September 30, 2019	15	$	362		435	$	7,145		$	(4	)	$	37		$	7,540



	Nine Months Ended September 30, 2018
	Series A Preferred Units				Common Units				Accumulated Other Comprehensive Loss		Noncontrolling Interest			Total Partners’ Equity
	Units	Value			Units	Value			Value		Value			Value

	(In millions)
Balance as of December 31, 2017	15	$	362		433	$	7,280		$	—	$	12		$	7,654
Net income	—	9			—	105			—		—			114
Distributions	—	(9		)	—	(139		)	—		(1		)	(149		)
Balance as of March 31, 2018	15	$	362		433	$	7,246		$	—	$	11		$	7,619
Net income	—	9			—	86			—		—			95
Distributions	—	(9		)	—	(137		)	—		—			(146		)
Equity-based compensation, net of units for employee taxes	—	—			—	3			—		—			3
Balance as of June 30, 2018	15	$	362		433	$	7,198		$	—	$	11		$	7,571
Net income	—	9			—	129			—		1			139
Issuance of common units	—	—			—	2					—			2
Distributions	—	(9		)	—	(137		)	—		(1		)	(147		)
Equity-based compensation, net of units for employee taxes	—	—			—	3			—		—			3
Balance as of September 30, 2018	15	$	362		433	$	7,195		$	—	$	11		$	7,568

See Notes to the Unaudited Condensed Consolidated Financial Statements

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ENABLE MIDSTREAM PARTNERS, LP

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

Organization

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

CenterPoint Energy and OGE Energy each have 50% of the management interests in Enable GP. Enable GP is the general partner of the Partnership and has no other operating activities. Enable GP is governed by a board made up of two representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership’s Chief Executive Officer and three independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP.

As of September 30, 2019, CenterPoint Energy held approximately 53.7% or 233,856,623 of the Partnership’s common units, and OGE Energy held approximately 25.5% or 110,982,805 of the Partnership’s common units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. The limited partner interests of the Partnership have limited voting rights on matters affecting the business. As such, limited partners do not have rights to elect the Partnership’s general partner on an annual or continuing basis and may not remove Enable GP, its current general partner, 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.

As of September 30, 2019, the Partnership owned a 50% interest in SESH. See Note 8 for further discussion of SESH. For the nine months ended September 30, 2019, the Partnership held a 50% ownership in Atoka and consolidated Atoka in its Condensed Consolidated Financial Statements as EOIT acted as the managing member of Atoka and had control over the operations of Atoka. In addition, beginning November 1, 2018 through September 30, 2019, the Partnership owned a 60% interest in ESCP, which is consolidated in its Condensed Consolidated Financial Statements as EOCS acted as the managing member of ESCP and had control over the operations of ESCP.

Basis of Presentation

The accompanying condensed 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 consolidated financial statements and related notes should be read in conjunction with the consolidated financial statements and related notes included in our Annual Report.

The condensed consolidated financial statements and the related notes 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 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 segments, see Note 16.

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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.

Depreciation Expense

The Partnership completed a depreciation study for the Gathering and Processing and Transportation and Storage segments. Effective January 1, 2019, the new depreciation rates have been applied prospectively as a change in accounting estimate. The new depreciation rates did not result in a material change in depreciation expense or results of operations.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are recorded at the invoiced amount and do not typically bear interest. The determination of the allowance for doubtful accounts requires management to make estimates and judgments regarding our customers’ ability to pay. The allowance for doubtful accounts is determined based upon specific identification and estimates of future uncollectable amounts. On an ongoing basis, we evaluate our customers’ financial strength based on aging of accounts receivable, payment history, and review of other relevant information, including ratings agency credit ratings and alerts, publicly available reports and news releases, and bank and trade references. It is the policy of management to review the outstanding accounts receivable at least quarterly, giving consideration to credit losses, the aging of receivables, specific customer circumstances that may impact their ability to pay the amounts due and current and forecasted economic conditions over the assets contractual lives. Based on this review, management determined that a $3 million and $2 million allowance for doubtful accounts was required at September 30, 2019 and December 31, 2018, respectively.

Inventory

Natural gas inventory is held, through the transportation and storage segment, to provide operational support for pipeline deliveries and to manage leased intrastate storage capacity. Natural gas liquids inventory is held, through the gathering and processing segment, due to timing differences between the production of certain natural gas liquids and ultimate sale to third parties. Natural gas and natural gas liquids inventory is valued using moving average cost and is subsequently recorded at the lower of cost or net realizable value. The Partnership recorded no write-downs to net realizable value related to natural gas and natural gas liquids inventory during the three months ended September 30, 2019 and 2018, respectively, and $6 million and $3 million during the nine months ended September 30, 2019 and 2018, respectively.

(2) New Accounting Pronouncements

Accounting Standards to be Adopted in Future Periods

Financial Instruments—Credit Losses

In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This standard requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions, and reasonable and supportable forecasts in order to record credit losses in a more timely manner. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.

Intangibles—Goodwill and Other

In January 2017, the FASB issued ASU No. 2017-04, “Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” This standard requires entities to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. The standard is effective for interim and annual reporting periods beginning after December 15, 2019. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.

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Fair Value Measurement—Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement

In August 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement” which focuses on improving the effectiveness of disclosures in the notes to the financial statements by facilitating clear communication of the information required by U.S. GAAP that is most important to users of each entity’s financial statements. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted. The Partnership expects to adopt this standard in the first quarter of 2020 and continues to evaluate the other impacts of the new standards on our Condensed Consolidated Financial Statements and related disclosures.

Intangibles—Goodwill and Other—Internal-Use Software

In August 2018, the FASB issued ASU No. 2018-15, “Intangibles—Goodwill and Other—Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract,” which aims to reduce complexity in the accounting for costs of implementing a cloud computing service arrangement. ASU No. 2018-15 aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.

Collaborative Arrangements

In November 2018, the FASB issued ASU No. 2018-18, “Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606.” This standard resolves the diversity in practice concerning the manner in which entities account for transactions on the basis of their view of the economics of the collaborative arrangement. The amendments (1) clarify that certain transactions between collaborative participants should be accounted for as revenue under topic 606 when the collaborative participant is a customer in the context of the unit of account; (2) add unit-of-account guidance in Topic 808 to align with the guidance in Topic 606; and (3) clarify that in a transaction that is not directly related to sales to third parties, presenting the transaction as revenue would be precluded if the collaborative participant counterparty was not a customer. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.

Codification Improvements

In April 2019, the FASB issued ASU No. 2019-04, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments,” which clarifies and improves areas of guidance related to recently issued standards on credit losses, hedging and recognition and measurement. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.

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(3) Revenues

The following tables disaggregate total revenues by major source from contracts with customers and the gain (loss) on derivative activity for the three and nine months ended September 30, 2019 and 2018.



	Three Months Ended September 30, 2019
	Gathering and Processing		Transportation and Storage		Eliminations			Total

	(In millions)
Revenues:
Product sales:
Natural gas	$	69	$	95	$	(69	)	$	95
Natural gas liquids	191		5		(5		)	191
Condensate	26		—		—			26
Total revenues from natural gas, natural gas liquids, and condensate	286		100		(74		)	312
Gain (loss) on derivative activity	8		—		—			8
Total Product sales	$	294	$	100	$	(74	)	$	320
Service revenues:
Demand revenues	$	97	$	119	$	—		$	216
Volume-dependent revenues	151		15		(3		)	163
Total Service revenues	$	248	$	134	$	(3	)	$	379
Total Revenues	$	542	$	234	$	(77	)	$	699



	Three Months Ended September 30, 2018
	Gathering and Processing			Transportation and Storage		Eliminations			Total

	(In millions)
Revenues:
Product sales:
Natural gas	$	87		$	146	$	(120	)	$	113
Natural gas liquids	439			7		(7		)	439
Condensate	25			—		—			25
Total revenues from natural gas, natural gas liquids, and condensate	551			153		(127		)	577
Loss on derivative activity	(23		)	—		(1		)	(24		)
Total Product sales	$	528		$	153	$	(128	)	$	553
Service revenues:
Demand revenues	$	92		$	114	$	—		$	206
Volume-dependent revenues	158			14		(3		)	169
Total Service revenues	$	250		$	128	$	(3	)	$	375
Total Revenues	$	778		$	281	$	(131	)	$	928

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	Nine Months Ended September 30, 2019
	Gathering and Processing		Transportation and Storage		Eliminations			Total

	(In millions)
Revenues:
Product sales:
Natural gas	$	291	$	365	$	(305	)	$	351
Natural gas liquids	698		16		(16		)	698
Condensate	93		—		—			93
Total revenues from natural gas, natural gas liquids, and condensate	1,082		381		(321		)	1,142
Gain (loss) on derivative activity	14		—		—			14
Total Product sales	$	1,096	$	381	$	(321	)	$	1,156
Service revenues:
Demand revenues	$	225	$	373	$	—		$	598
Volume-dependent revenues	438		48		(11		)	475
Total Service revenues	$	663	$	421	$	(11	)	$	1,073
Total Revenues	$	1,759	$	802	$	(332	)	$	2,229



	Nine Months Ended September 30, 2018
	Gathering and Processing			Transportation and Storage		Eliminations			Total

	(In millions)
Revenues:
Product sales:
Natural gas	$	299		$	420	$	(336	)	$	383
Natural gas liquids	1,054			20		(20		)	1,054
Condensate	98			—		—			98
Total revenues from natural gas, natural gas liquids, and condensate	1,451			440		(356		)	1,535
Gain (loss) on derivative activity	(40		)	2		—			(38		)
Total Product sales	$	1,411		$	442	$	(356	)	$	1,497
Service revenues:
Demand revenues	$	194		$	347	$	—		$	541
Volume-dependent revenues	405			48		(10		)	443
Total Service revenues	$	599		$	395	$	(10	)	$	984
Total Revenues	$	2,010		$	837	$	(366	)	$	2,481

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Accounts Receivable

The table below summarizes the change in accounts receivable for the nine months ended September 30, 2019.



	September 30, 2019		December 31, 2018

	(In millions)
Accounts Receivable:
Customers	$	281	$	297
Contract assets ⁽¹⁾	4		6
Non-customers	5		6
Total Accounts Receivable ⁽²⁾	$	290	$	309

____________________

(1)

Contract assets reflected in Total Accounts Receivable include accrued minimum volume commitments. Contract assets are primarily attributable to revenues associated with estimated shortfall volumes on certain annual minimum volume commitment arrangements. Total Accounts Receivable does not include $5 million of contracts assets related to firm service transportation contracts with tiered rates, which are reflected in Other Assets.


(2)	Total Accounts Receivable includes Accounts receivable, net of allowance for doubtful accounts and Accounts receivable—affiliated companies.

Contract Liabilities

Our contract liabilities primarily consist of prepayments received from customers for which the good or service has not yet been provided in connection with the prepayment. The table below summarizes the change in the contract liabilities for the nine months ended September 30, 2019:



	September 30, 2019		December 31, 2018		Amounts recognized in revenues

	(In millions)
Deferred revenues	$	46	$	48	$	23

The table below summarizes the timing of recognition of these contract liabilities as of September 30, 2019:



	2019		2020		2021		2022		2023 and After
	(In millions)
Deferred revenues	$	19	$	6	$	5	$	5	$	11

Remaining Performance Obligations

Our remaining performance obligations consist primarily of firm arrangements and minimum volume commitment arrangements. Upon completion of the performance obligations associated with these arrangements, customers are invoiced and revenue is recognized as Service revenues in the Condensed Consolidated Statements of Income. The table below summarizes the timing of recognition of the remaining performance obligations as of September 30, 2019:



	2019		2020		2021		2022		2023 and After
	(In millions)
Transportation and Storage	$	119	$	419	$	229	$	172	$	822
Gathering and Processing	47		163		136		138		460
Total remaining performance obligations	$	166	$	582	$	365	$	310	$	1,282

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(4) Leases

On January 1, 2019, the Partnership adopted ASU 2016-02, “Leases (ASC 842).” This standard requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Partnership has applied the standard to only contracts that were not expired as of January 1, 2019.

The Partnership elected the optional transition practical expedient to not evaluate land easements that exist or expire before the Partnership's adoption of ASC 842 and that were not previously accounted for as leases under ASC 840. The Partnership elected the optional transition practical expedient to not reassess whether any expired or existing contracts are or contain leases, the lease classification for any expired or existing leases and initial direct costs for any existing leases. Upon adoption, we increased our asset and liability balances on the Condensed Consolidated Balance Sheets by approximately $35 million due to the required recognition of right-of-use assets and corresponding lease liabilities for all lease obligations that were classified as operating leases. The Partnership did not recognize a material cumulative adjustment to the Condensed Consolidated Statement of Partners’ Equity and we did not have any material changes in the timing of expense recognition or our accounting policies.

Our lease obligations are primarily comprised of rentals of field equipment and buildings, which are recorded as Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income. Other than the contractual terms for each lease obligation, the key inputs for our calculations of the initial right-of-use assets and corresponding lease liabilities are the expected remaining life and applicable discount rate. Field equipment has an expected lease term of three to five years, with contractual base terms of one to three years followed by month-to-month renewals. Field equipment rental arrangements do not generally contain any significant variable lease payments. While certain arrangements may include lower standby rates, field equipment is generally anticipated to be in use for all of its expected lease term. Buildings have an expected lease term of seven to ten years, which is currently the same as the contractual base term. Building rental arrangements contain market-based renewal options of up to 15 years. Variable lease payments for buildings are generally comprised of costs for utilities, maintenance and building management services. There were no variable lease payments due under building rental arrangements until July 1, 2019, after which amounts are due monthly. The Partnership is generally not aware of the implicit rate for either field equipment or building rental arrangements, so discount rates are based upon the expected term of each arrangement and the Partnership’s uncollateralized borrowing rate associated with the expected term at the time of lease inception. As of September 30, 2019, the weighted average remaining lease term is 6.6 years and the weighted average discount rate is 5.52%.

As of September 30, 2019, we have right-of-use assets of $36 million recorded as Other Assets, $11 million of corresponding obligations recorded as Other Current Liabilities and $28 million of corresponding obligations recorded as Other Liabilities on the Partnership’s Condensed Consolidated Balance Sheet. All lease obligations outstanding during the three and nine months ended September 30, 2019 were classified as operating leases, therefore all cash flows are reflected in Cash Flows from Operating Activities. Rental costs associated with field equipment and buildings were $6 million and $1 million during the three months ended September 30, 2019, respectively, and $18 million and $5 million during the nine months ended September 30, 2019, respectively.

The table below summarizes lease expense for the three and nine months ended September 30, 2019:



	Three Months Ended September 30, 2019
	Gathering and Processing		Transportation and Storage		Total

	(In millions)
Lease Expense:
Lease Cost:
Operating lease cost	$	2	$	—	$	2
Short-term lease cost	3		1		4
Variable lease cost	1		—		1
Total Lease Cost	$	6	$	1	$	7

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	Nine Months Ended September 30, 2019
	Gathering and Processing		Transportation and Storage		Total

	(In millions)
Lease Expense:
Lease Cost:
Operating lease cost	$	7	$	—	$	7
Short-term lease cost	14		1		15
Variable lease cost	1		—		1
Total Lease Cost	$	22	$	1	$	23

Under ASC 842, as of September 30, 2019, the Partnership has operating lease obligations expiring at various dates. The $17 million difference between undiscounted cash flows for operating leases and our $39 million of lease obligations is due to the impact of the applicable discount rate. Undiscounted cash flows for operating lease liabilities are as follows:



	Year Ended December 31,
	2019		2020		2021		2022		2023		2024 and After		Total

	(In millions)
Noncancellable operating leases	$	11	$	11	$	7	$	6	$	6	$	15	$	56

Under ASC 840, as of December 31, 2018, the Partnership had the following operating lease obligations as well as the estimate of the period in which the obligation will be settled:



	Year Ended December 31,
	2019		2020-2021		2022-2023		After 2023		Total

	(In millions)
Noncancellable operating leases	$	14	$	6	$	6	$	14	$	40

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(5) Acquisition

Velocity Holdings, LLC Acquisition

On November 1, 2018, the Partnership acquired all of the equity interests in Velocity Holdings, LLC, now EOCS, which owns and operates a crude oil and condensate gathering system in the SCOOP and STACK plays of the Anadarko Basin, for approximately $444 million in cash, subject to certain customary working capital adjustments. The acquisition was accounted for as a business combination and was funded with borrowings under the commercial paper program. During the fourth quarter of 2018, the Partnership finalized the purchase price allocation as of November 1, 2018.

The following table presents the fair value of the identified assets acquired and liabilities assumed at the acquisition date:



Purchase price allocation:
Assets acquired:
Cash	$	1
Current Assets	3
Property, plant and equipment	124
Intangibles	259
Goodwill	86
Liabilities assumed:
Current liabilities	1
Less: Non-Controlling Interest at fair value	28
Total identifiable net assets	$	444

The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 15 years. Goodwill recognized from the acquisition primarily relates to greater operating leverage in the Anadarko Basin and is allocated to the gathering and processing segment. Included within the acquisition was 60% of a 26-mile pipeline system joint venture with a third party which owns and operates a refinery connected to the EOCS system. This joint venture’s financials have been consolidated within the Partnership’s financial statements resulting in $28 million in non-controlling interest. The Partnership incurred approximately $6 million of acquisition costs associated with this transaction, which were included in General and administrative expense in the Consolidated Statements of Income for the twelve months ended December 31, 2018. The Partnership determined not to include pro forma consolidated financial statements for the periods presented as the impact would not be material.

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(6) Earnings Per Limited Partner Unit

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018

	(In millions, except per unit data)
Net income	$	133	$	139	$	380	$	348
Net income attributable to noncontrolling interest	1		1		2		1
Series A Preferred Unit distributions	9		9		27		27
General partner interest in net income	—		—		—		—
Net income available to common unitholders	$	123	$	129	$	351	$	320

Net income allocable to common units	$	123	$	129	$	351	$	320
Dilutive effect of Series A Preferred Unit distributions	—		—		—		—
Diluted net income allocable to common units	$	123	$	129	$	351	$	320

Basic earnings per unit
Common units	$	0.28	$	0.30	$	0.81	$	0.74

Basic weighted average number of common units outstanding ⁽¹⁾	437		435		436		434
Dilutive effect of Series A Preferred Units	—		—		—		—
Dilutive effect of performance units	—		1		—		2
Diluted weighted average number of common units outstanding	437		436		436		436

Diluted earnings per unit
Common units	$	0.28	$	0.30	$	0.81	$	0.73

____________________


(1)	Basic weighted average number of outstanding common units includes approximately two million time-based phantom units for each of the three months ended September 30, 2019 and 2018, respectively, and one million time-based phantom units for each of the nine months ended September 30, 2019 and 2018, respectively.

(7) Partners’ Equity

The Partnership Agreement requires that, within 60 days after the end of each quarter, the Partnership distribute all of its available cash (as defined in the Partnership Agreement) to unitholders of record on the applicable record date.

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The Partnership paid or has authorized payment of the following cash distributions to common unitholders, as applicable, during 2018 and 2019 (in millions, except for per unit amounts):

Three Months Ended

Record Date

Payment Date

Per Unit Distribution

Total Cash Distribution

September 30, 2019⁽¹⁾

November 19, 2019

November 26, 2019

0.3305

144

June 30, 2019

August 20, 2019

August 27, 2019

0.3305

144

March 31, 2019

May 21, 2019

May 29, 2019

0.318

138

December 31, 2018

February 19, 2019

February 26, 2019

0.318

138

September 30, 2018

November 16, 2018

November 29, 2018

0.318

138

June 30, 2018

August 21, 2018

August 28, 2018

0.318

138

March 31, 2018

May 22, 2018

May 29, 2018

0.318

138

_____________________


(1)	The Board of Directors declared this $0.3305 per common unit cash distribution on November 5, 2019, to be paid on November 26, 2019 to common unitholders of record at the close of business on November 19, 2019.

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2018 and 2019 (in millions, except for per unit amounts):

Three Months Ended

Record Date

Payment Date

Per Unit Distribution

Total Cash Distribution

September 30, 2019 ⁽¹⁾

November 5, 2019

November 14, 2019

0.625

June 30, 2019

August 2, 2019

August 14, 2019

0.625

March 31, 2019

April 29, 2019

May 15, 2019

0.625

December 31, 2018

February 8, 2019

February 14, 2019

0.625

September 30, 2018

November 6, 2018

November 14, 2018

0.625

June 30, 2018

August 1, 2018

August 14, 2018

0.625

March 31, 2018

May 1, 2018

May 15, 2018

0.625

_____________________


(1)	The Board of Directors declared a $0.625 per Series A Preferred Unit cash distribution on November 5, 2019, to be paid on November 14, 2019, to Series A Preferred unitholders of record at the close of business on November 5, 2019.

ATM Program

On May 12, 2017, the Partnership entered into an ATM Equity Offering Sales Agreement, pursuant to which the Partnership may issue and sell common units having an aggregate offering price of up to $200 million, by sales methods and at prices determined by market conditions and other factors at the time of our offerings. The Partnership has no obligation to sell any common units under the ATM Program and the Partnership may suspend sales under the ATM Program at any time. During the nine months ended September 30, 2019 and 2018, the Partnership did not issue common units under the ATM Program. As of September 30, 2019, $197 million of common units remained available for issuance through the ATM Program.

(8) Investment in Equity Method Affiliate

The Partnership uses the equity method of accounting for investments in entities in which it has an ownership interest between 20% and 50% and exercises significant influence.

SESH is owned 50% by Enbridge, Inc. and 50% by the Partnership. Pursuant to the terms of the SESH LLC Agreement, if, at any time, CenterPoint Energy has a right to receive less than 50% of our distributions through its interest in the Partnership and its economic interest in Enable GP, or does not have the ability to exercise certain control rights, Enbridge, Inc. may, under certain circumstances, have the right to purchase the Partnership’s interest in SESH at fair market value, subject to certain exceptions.

The Partnership shares operations of SESH with Enbridge, Inc. under service agreements. The Partnership is responsible for the field operations of SESH. SESH reimburses each party for actual costs incurred, which are billed based upon a combination of direct charges and allocations. The Partnership billed SESH $2 million and $6 million during the three months ended September

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30, 2019 and 2018, respectively, and $12 million and $14 million during the nine months ended September 30, 2019 and 2018, respectively, associated with these service agreements.

The Partnership includes equity in earnings of equity method affiliate under the Other Income (Expense) caption in the Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2019 and 2018.

SESH:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018

	(In millions)
Equity in Earnings of Equity Method Affiliate	$	5	$	7	$	12	$	20
Distributions from Equity Method Affiliate ⁽¹⁾	$	4	$	10	$	20	$	31

___________________


(1)	Distributions from equity method affiliate includes a $12 million and $20 million return on investment and a $8 million and $11 million return of investment for the nine months ended September 30, 2019 and 2018, respectively.

Summarized financial information of SESH:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018

	(In millions)
Income Statements:
Revenues	$	27	$	29	$	81	$	85
Operating income	$	15	$	18	$	37	$	51
Net income	$	10	$	13	$	24	$	38

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(9) Debt

The following table presents the Partnership’s outstanding debt as of September 30, 2019 and December 31, 2018.



	September 30, 2019							December 31, 2018
	Outstanding Principal		Premium (Discount)			Total Debt		Outstanding Principal		Premium (Discount)			Total Debt

	(In millions)
Commercial Paper	$	182	$	—		$	182	$	649	$	—		$	649
Revolving Credit Facility	—		—			—		250		—			250
2019 Term Loan Agreement	800		—			800		—		—			—
2019 Notes	—		—			—		500		—			500
2024 Notes	600		—			600		600		—			600
2027 Notes	700		(2		)	698		700		(2		)	698
2028 Notes	800		(6		)	794		800		(6		)	794
2029 Notes	550		(1		)	549		—		—			—
2044 Notes	550		—			550		550		—			550
EOIT Senior Notes	250		3			253		250		7			257
Total debt	$	4,432	$	(6	)	$	4,426	$	4,299	$	(1	)	$	4,298
Less: Short-term debt ⁽¹⁾						182							649
Less: Current portion of long-term debt ⁽²⁾						253							500
Less: Unamortized debt expense⁽³⁾						23							20
Total long-term debt						$	3,968						$	3,129

____________________


(1)	Short-term debt includes $182 million and $649 million of outstanding commercial paper as of September 30, 2019 and December 31, 2018, respectively.


(2)	As of September 30, 2019, Current portion of long-term debt included $253 million outstanding balance of the EOIT Senior Notes due March 15, 2020. As of December 31, 2018, Current portion of long-term debt included $500 million outstanding balance of the 2019 Notes due May 15, 2019.


(3)	As of September 30, 2019 and December 31, 2018, there was an additional $5 million and $6 million, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above.

Commercial Paper

The Partnership has a commercial paper program, pursuant to which the Partnership is authorized to issue up to $1.4 billion of commercial paper. The commercial paper program is supported by our Revolving Credit Facility, and outstanding commercial paper effectively reduces our borrowing capacity thereunder. There were $182 million and $649 million outstanding under our commercial paper program at September 30, 2019 and December 31, 2018, respectively. The weighted average interest rate for the outstanding commercial paper was 2.96% as of September 30, 2019.

Revolving Credit Facility

On April 6, 2018, the Partnership amended and restated its Revolving Credit Facility. As amended and restated, the Revolving Credit Facility is a $1.75 billion, 5-year senior unsecured revolving credit facility, which under certain circumstances may be increased from time to time up to an additional $875 million. The Revolving Credit Facility is scheduled to mature on April 6, 2023, subject to an extension option, which could be exercised two times to extend the term of the Revolving Credit Facility, in each case, for an additional one-year term. As of September 30, 2019, there were no principal advances and $3 million in letters of credit outstanding under the Revolving Credit Facility.

The Revolving Credit Facility provides that outstanding borrowings bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s designated credit ratings from S&P, Moody’s and Fitch Ratings. As of September 30, 2019, the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was 1.50% based on the Partnership’s credit ratings. In addition, the Revolving Credit Facility requires the Partnership to pay a fee on unused commitments. The commitment fee is based on the Partnership’s credit ratings. As of September 30, 2019, the commitment fee under the restated Revolving Credit Facility was 0.20% per annum based on the

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Partnership’s credit ratings. The commitment fee is recorded as interest expense in the Partnership’s Condensed Consolidated Statements of Income.

2019 Term Loan Agreement

On January 29, 2019, the Partnership entered into an unsecured term loan agreement with Bank of America, N.A., as administrative agent, and the several lenders thereto. The 2019 Term Loan Agreement has a scheduled maturity date of January 29, 2022, but contains an option, which may be exercised up to two times, to extend the maturity date for an additional one-year term. The 2019 Term Loan Agreement provides that outstanding borrowings bear interest at the eurodollar rate and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s credit ratings. The applicable margin shall equal, (1) in the case of interest rates determined by reference to the eurodollar rate, between 0.75% and 1.50% per annum and (2) in the case of interest rates determined by reference to the alternate base rate, between 0% and 0.50% per annum. As of September 30, 2019, the applicable margin for LIBOR-based advances under the 2019 Term Loan Facility was 1.25% based on the Partnership’s credit ratings. As of September 30, 2019, the weighted average interest rate of the 2019 Term Loan Agreement was 3.33%.

Prior to the expiration of the availability period for advances on July 26, 2019, the Partnership drew $1 billion in advances under the Term Loan Agreement, which were used for general partnership purposes. Advances under the 2019 Term Loan Agreement can be prepaid, in whole or in part, at any time without premium or penalty, other than usual and customary LIBOR breakage costs, if applicable. On September 16, 2019, the Partnership prepaid $200 million of the advances under the Term Loan Agreement, the repayment of which was not subject to LIBOR breakage costs. As of September 30, 2019, there was $800 million outstanding under the 2019 Term Loan Agreement.

The 2019 Term Loan Agreement contains a financial covenant requiring the Partnership to maintain a ratio of consolidated funded debt to consolidated EBITDA as of the last day of each fiscal quarter of less than or equal to 5.00 to 1.00; provided that, for a certain period time following an acquisition by the Partnership or certain of its subsidiaries with a purchase price that when combined with the aggregate purchase price for all other such acquisitions in any rolling 12-month period, is equal to or greater than $25 million, the consolidated funded debt to consolidated EBITDA ratio as of the last day of each such fiscal quarter during such period would be permitted to be up to 5.50 to 1.00.

The 2019 Term Loan Agreement also contains covenants that restrict the Partnership and certain of its subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of subsidiary indebtedness, incurrence of liens, transactions with affiliates, designation of subsidiaries as Excluded Subsidiaries (as defined in the 2019 Term Loan Agreement), restricted payments, changes in the nature of their respective business and entering into certain restrictive agreements. The 2019 Term Loan Agreement is subject to acceleration upon the occurrence of certain defaults, including, among others, payment defaults on such facility, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100 million or more in the aggregate, change of control, nonpayment of uninsured judgments in excess of $100 million, and the occurrence of certain ERISA and bankruptcy events, subject, where applicable, to specified cure periods.

Senior Notes

On September 13, 2019, the Partnership completed the public offering of $550 million aggregate principal amount of its 4.15% Senior Notes due 2029. The Partnership received net proceeds of approximately $544 million, after deducting the underwriting discount and offering expenses. The net proceeds were used to repay $200 million of borrowings outstanding under the 2019 Term Loan Agreement, to repay amounts outstanding under the commercial paper program, and for general partnership purposes. The Partnership intends to issue commercial paper to repay the full amount of the EOIT Senior Notes at maturity. The 2029 Notes had an unamortized discount of $1 million and unamortized debt expense of $5 million at September 30, 2019, resulting in an effective interest rate of 4.31% from the issue date through September 30, 2019.

As of September 30, 2019, the Partnership’s debt also included the 2024 Notes, 2027 Notes, 2028 Notes and 2044 Notes, which had $8 million of unamortized discount and $18 million of unamortized debt expense at September 30, 2019, resulting in effective interest rates of 4.01%, 4.57%, 5.20% and 5.08%, respectively, during the nine months ended September 30, 2019. In May 2019, the Partnership’s 2019 Notes matured and were paid using proceeds from the 2019 Term Loan Agreement.

As of September 30, 2019, the Partnership’s debt included EOIT’s Senior Notes. The EOIT Senior Notes had $3 million of unamortized premium at September 30, 2019, resulting in an effective interest rate of 3.82% during the nine months ended September 30, 2019.

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As of September 30, 2019, the Partnership and EOIT were in compliance with all of their debt agreements, including financial covenants.

(10) Derivative Instruments and Hedging Activities

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

Commodity Price Risk

The Partnership uses forward physical contracts, commodity price swap contracts and commodity price option features to manage its commodity price risk exposures. Commodity derivative instruments used by the Partnership are as follows:


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


•	natural gas futures and swaps, natural gas options, natural gas swaptions and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas price exposure associated with its gathering, processing, transportation and storage assets, 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 its gathering and processing business.

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 are recorded as Other Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value on a net basis with such amounts classified as current or long-term based on their anticipated settlement.

As of September 30, 2019 and December 31, 2018, the Partnership had no commodity derivative instruments that were designated as cash flow or fair value hedges for accounting purposes.

Interest Rate Risk

The Partnership uses interest rate swap contracts to manage its interest rate risk exposures. The Partnership recognizes its interest rate 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. The Partnership’s interest rate swap contracts are designated as cash flow hedging instruments for accounting purposes. For interest rate derivative instruments designated as cash flow hedging instruments, the gain or loss on the derivative is recognized currently in Accumulated other comprehensive loss and will be reclassified to Interest expense in the same period the hedged transaction affects earnings. As of September 30, 2019, the Partnership had no interest rate derivative instruments that were designated as fair value hedges for accounting purposes. As of December 31, 2018, the Partnership had no outstanding interest rate derivative instruments.

Credit Risk

Credit risk includes the risk that counterparties that owe the Partnership money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Partnership may seek or be forced to enter into alternative arrangements. In that event, the Partnership’s financial results could be adversely affected, and the Partnership could incur losses.

Derivatives Not Designated as Hedging Instruments

Derivative instruments not designated as hedging instruments for accounting purposes are utilized to manage its exposure to commodity price risk. For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

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Quantitative Disclosures Related to Derivative Instruments Not Designated as Hedging 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, 2019 and December 31, 2018, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:



	September 30, 2019		December 31, 2018
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas—TBtu ⁽¹⁾
Financial fixed futures/swaps	13	22	16	28
Financial basis futures/swaps	16	40	18	29
Financial swaptions ⁽³⁾	—	3	—	1
Physical purchases/sales	—	7	—	11
Crude oil (for condensate)—MBbl ⁽²⁾
Financial futures/swaps	—	915	—	945
Financial swaptions ⁽³⁾	—	90	—	30
Natural gas liquids—MBbl ⁽⁴⁾
Financial futures/swaps	3,210	3,165	270	2,535

____________________


(1)	As of September 30, 2019, 85.6% of the natural gas contracts had durations of one year or less and 14.4% had durations of more than one year and less than two years. As of December 31, 2018, 74.0% of the natural gas contracts had durations of one year or less, 24.2% had durations of more than one year and less than two years and 1.8% had durations of more than two years.


(2)	As of September 30, 2019, 83.6% of the crude oil (for condensate) contracts had durations of one year or less and 16.4% had durations of more than one year and less than two years. As of December 31, 2018, 76.9% of the crude oil (for condensate) contracts had durations of one year or less and 23.1% had durations of more than one year and less than two years.


(3)	The notional contains a combined derivative instrument consisting of a fixed price swap and a sold option, which gives the counterparties the right, but not the obligation, to increase the notional quantity hedged under the fixed price swap until the option expiration date. The notional volume represents the volume prior to option exercise.


(4)	As of September 30, 2019, 69.2% of the natural gas liquids contracts had durations of one year or less and 30.8% had durations of more than one year and less than two years. As of December 31, 2018, 86.1% of the natural gas liquid contracts had durations of one year or less and 13.9% had durations of more than one year and less than two years.

Derivatives Designated as Hedging Instruments

Derivative instruments designated as hedging instruments for accounting purposes are utilized in managing the Partnership’s interest rate risk exposures.

Quantitative Disclosures Related to Derivative Instruments Designated as Hedging Instruments

The derivative instruments designated as hedges for accounting purposes are interest rate derivative instruments priced on monthly interest rates.

As of September 30, 2019 and December 31, 2018, the Partnership had the following derivative instruments that were designated as hedging instruments for accounting purposes:



	September 30, 2019		December 31, 2018
	Gross Notional Value
	(In millions)
Interest rate swaps	$	300	$	—

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Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018 that were not designated as hedging instruments for accounting purposes are as follows:



		September 30, 2019				December 31, 2018
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities

		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	10	$	6	$	3	$	5
Financial futures/swaps	Other	—		1		—		2
Physical purchases/sales	Other Current	4		—		3		—
Physical purchases/sales	Other	1		—		4		—
Crude oil (for condensate)
Financial futures/swaps	Other Current	4		14		9		3
Financial futures/swaps	Other	—		8		2		—
Natural gas liquids
Financial futures/swaps	Other Current	26		5		10		1
Financial futures/swaps	Other	10		2		2		—
Total gross commodity derivatives ⁽¹⁾		$	55	$	36	$	33	$	11

_____________________


(1)	See Note 11 for a reconciliation of the Partnership’s commodity derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018.

The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018 that were designated as hedging instruments for accounting purposes are as follows:



		September 30, 2019				December 31, 2018
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities

		(In millions)
Interest rate swaps	Other Current	$	—	$	1	$	—	$	—
Interest rate swaps	Other	—		3		—		—
Total gross interest rate derivatives ⁽¹⁾		$	—	$	4	$	—	$	—

_____________________


(1)	All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of September 30, 2019.

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Income Statement Presentation Related to Derivative Instruments

The following table presents the effect of derivative instruments on the Partnership’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2019 and 2018:



	Amounts Recognized in Income
	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018

	(In millions)
Natural gas
Financial futures/swaps gains (losses)	$	2		$	(1	)	$	10		$	(6	)
Physical purchases/sales gains	1			—			1			5
Crude oil (for condensate)
Financial futures/swaps losses	(8		)	(4		)	(29		)	(14		)
Natural gas liquids
Financial futures/swaps gains (losses)	13			(19		)	32			(23		)
Interest Rates
Financial futures/swaps gains (losses)	—			—			—			—
Total	$	8		$	(24	)	$	14		$	(38	)

For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended September 30, 2019 and 2018, if any, are reported in Product sales.

The following table presents the components of gain (loss) on derivative activity in the Partnership’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2019 and 2018:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018

	(In millions)
Change in fair value of commodity derivatives	$	(2	)	$	(16	)	$	(3	)	$	(28	)
Realized gain (loss) on commodity derivatives	10			(8		)	17			(10		)
Gain (loss) on commodity derivative activity	$	8		$	(24	)	$	14		$	(38	)

Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody’s or S&P were to lower the Partnership’s senior unsecured debt rating to a below investment grade rating, the Partnership could be required to provide additional credit assurances to third parties, which could include letters of credit or cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position. As of September 30, 2019, under these obligations, the Partnership has posted no cash collateral related to natural gas swaps and swaptions, crude swaps and swaptions and NGL swaps and no additional collateral would be required to be posted by the Partnership in the event of a credit ratings downgrade to a below investment grade rating. In certain situations where the Partnership’s credit rating is lowered by Moody’s or S&P, the Partnership could be subject to an early termination event related to certain derivative instruments, which could result in a cash settlement of the instruments at market values on the date of such early termination.

(11) 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 either the NYMEX or the ICE and settled through either a NYMEX or ICE 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 generally include over-the-counter natural gas swaps, natural gas swaptions, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX or the ICE pricing, over-the-counter WTI crude oil swaps and swaptions for condensate sales, and over-the-counter interest rate swaps traded in observable markets with less volume and transaction frequency than active markets. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements.

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, ICE or WTI published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX or ICE published market prices may be considered Level 1 if they are settled through a NYMEX or ICE clearing broker account with daily margining. Over-the-counter derivatives with NYMEX, ICE 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. Certain derivatives with option features may be classified as Level 2 if valued using an industry standard Black-Scholes option pricing model that contain observable inputs in the marketplace throughout the term of the derivative instrument. 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. As of September 30, 2019, there were no contracts 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 three and nine months ended September 30, 2019, there were no transfers between levels.

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

Estimated Fair Value of Financial Instruments

The fair values of all accounts receivable, notes receivable, accounts payable, commercial paper and other such financial instruments on the Condensed Consolidated Balance Sheets are estimated to be approximately equivalent to their carrying amounts due to their short-term nature and have been excluded from the table below. The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments as of September 30, 2019 and December 31, 2018.



	September 30, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value

	(In millions)
Debt
Revolving Credit Facility (Level 2) ⁽¹⁾	$	—	$	—	$	250	$	250
2019 Term Loan Agreement (Level 2)	800		800		—		—
2019 Notes (Level 2)	—		—		500		497
2024 Notes (Level 2)	600		612		600		571
2027 Notes (Level 2)	698		701		698		642
2028 Notes (Level 2)	794		829		794		764
2029 Notes (Level 2)	549		529		—		—
2044 Notes (Level 2)	550		500		550		445
EOIT Senior Notes (Level 2)	253		253		257		256

____________________


(1)	Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $182 million and $649 million of commercial paper was outstanding as of September 30, 2019 and December 31, 2018, respectively.

The fair value of the Partnership’s Revolving Credit Facility, 2019 Term Loan Agreement, 2019 Notes, 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes, 2044 Notes and EOIT Senior 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). As of September 30, 2019, no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities.

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.

As of September 30, 2019, the Partnership’s Level 2 interest rate derivatives are recorded as liabilities with no netting adjustments. The following tables summarize the Partnership’s other assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2019 and December 31, 2018:



September 30, 2019	Commodity Contracts						Gas Imbalances ⁽¹⁾
	Assets			Liabilities			Assets ⁽²⁾		Liabilities ⁽³⁾

	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	8		$	28		$	—	$	—
Significant other observable inputs (Level 2)	47			8			8		8
Unobservable inputs (Level 3)	—			—			—		—
Total fair value	55			36			8		8
Netting adjustments	(36		)	(36		)	—		—
Total	$	19		$	—		$	8	$	8



December 31, 2018	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		$	9		$	—	$	—
Significant other observable inputs (Level 2)	29			2			18		17
Unobservable inputs (Level 3)	—			—			—		—
Total fair value	33			11			18		17
Netting adjustments	(9		)	(9		)	—		—
Total	$	24		$	2		$	18	$	17

______________________


(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. There were no netting adjustments as of September 30, 2019 and December 31, 2018.


(2)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $15 million and $11 million at September 30, 2019 and December 31, 2018, 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 $9 million and $5 million at September 30, 2019 and December 31, 2018, 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.

(12) Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:



	Nine Months Ended September 30,
	2019		2018

	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	131	$	90
Income taxes, net of refunds	1		3
Non-cash transactions:
Accounts payable related to capital expenditures	26		56
Lease liabilities arising from the application of ASC 842	42		—

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



	September 30,
	2019		2018

	(In millions)
Cash and cash equivalents	$	12	$	8
Restricted cash	1		14
Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	13	$	22

During the nine months ended September 30, 2019, Restricted cash decreased $13 million due to the release of cash collateral which was provided as credit assurance by a third party.

(13) Related Party Transactions

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

Transportation and Storage Agreements

Transportation and Storage Agreements with CenterPoint Energy

EGT provides natural gas transportation and storage services to CenterPoint Energy’s LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas under a combination of contracts that include the following types of services: firm transportation, firm transportation with seasonal demand, firm storage, no-notice transportation with storage and maximum rate firm transportation. The contracts for firm transportation with seasonal demand will remain in effect through March 31, 2021. The contracts for firm transportation, firm storage and firm no-notice transportation with storage, as well as the contracts for maximum rate firm transportation for Oklahoma and portions of Northeast Texas, are in effect through March 31, 2021, and will remain in effect thereafter unless and until terminated by either party upon 180 days’ prior written notice. The contracts for maximum firm rate transportation for Arkansas, Louisiana and Texarkana, Texas terminated on March 31, 2018. MRT provides firm transportation and firm storage services to CenterPoint Energy’s LDCs in Arkansas and Louisiana. Contracts for these services are in effect through May 15, 2023 and will remain in effect thereafter unless and until terminated by either party upon twelve months’ prior written notice.

Transportation and Storage Agreement with OGE Energy

EOIT provides no-notice load-following transportation and storage services to OGE Energy. On March 17, 2014, EOIT entered into a transportation agreement with OGE Energy, for four of its generating facilities, with a primary term of May 1, 2014 through April 30, 2019. On October 24, 2018, EOIT entered into a no-notice load-following transportation agreement with OGE Energy, with a primary term of April 1, 2019 through May 1, 2024. Following the primary term, the agreement will remain in effect from year to year thereafter unless either party provides notice of termination to the other party at least 180 days prior to the commencement of the succeeding annual period. On December 6, 2016, EOIT entered into an additional firm transportation agreement with OGE Energy, for one of its generating facilities with a primary term of December 1, 2018 through December 1, 2038.

Gas Sales and Purchases Transactions

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

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The Partnership’s revenues from affiliated companies accounted for 5% and 4% of total revenues during the three months ended September 30, 2019 and 2018, respectively, and 6% and 5% of total revenues during the nine months ended September 30, 2019 and 2018, respectively. Amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018

	(In millions)
Gas transportation and storage service revenues — CenterPoint Energy	$	22	$	22	$	78	$	79
Natural gas product sales — CenterPoint Energy	3		1		7		9
Gas transportation and storage service revenues — OGE Energy	9		9		35		27
Natural gas product sales — OGE Energy	4		1		5		3
Total revenues — affiliated companies	$	38	$	33	$	125	$	118

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018

	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	—	$	—	$	—	$	2
Cost of natural gas purchases — OGE Energy	12		7		25		15
Total cost of natural gas purchases — affiliated companies	$	12	$	7	$	25	$	17

Seconded employees and corporate services

As of September 30, 2019, the Partnership had certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. The Partnership’s reimbursement of OGE Energy for seconded employee costs arising out of OGE Energy’s defined benefit and retiree medical plans is fixed at actual cost subject to a cap of $5 million in 2019 and thereafter, unless and until secondment is terminated.

The Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under services agreements for an initial term that ended on April 30, 2016. The services agreements automatically extend year-to-year at the end of the initial term, unless terminated by the Partnership with at least 90 days’ notice prior to the end of any extension. Additionally, the Partnership may terminate the services 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 2019 are $1 million and $1 million, respectively.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018

	(In millions)
Corporate Services — CenterPoint Energy	$	—	$	1	$	—	$	2
Seconded Employee Costs — OGE Energy	4		6		15		21
Corporate Services — OGE Energy	—		—		—		1
Total corporate services and seconded employee costs	$	4	$	7	$	15	$	24

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(14) Commitments and Contingencies

The Partnership is routinely 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 may from time to time 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 currently expect the disposition of these matters to have a material adverse effect on its financial condition, results of operations or cash flows.

On January 1, 2017, the Partnership entered into a 10-year gathering and processing agreement, which became effective on July 1, 2018, with an affiliate of Energy Transfer Partners, LP for 400 MMcf/d of deliveries to the Godley Plant in Johnson County, Texas. As of September 30, 2019, the Partnership estimates the remaining associated 10-year minimum volume commitment fee to be $198 million.

On September 13, 2018, the Partnership executed a precedent agreement for the development of the Gulf Run Pipeline, an interstate natural gas transportation project. On January 30, 2019, a final investment decision was made by Golden Pass LNG, the cornerstone shipper for the LNG facility to be served by the Gulf Run Pipeline project. Subject to approval of the project by FERC, the Partnership will be required to construct a large-diameter pipeline from northern Louisiana to Gulf Coast markets. In addition, the Partnership may transfer existing EGT transportation infrastructure to the Gulf Run Pipeline. Under the precedent agreement, the Partnership estimates the cost to complete the Gulf Run Pipeline project would be as much as $550 million and the project is backed by a 20-year firm transportation service. The Gulf Run Pipeline connects natural gas producing regions in the U.S., including the Haynesville, Marcellus, Utica and Barnett shales and the Mid-Continent region. The project is expected to be placed into service in 2022.

On September 23, 2019, the Partnership entered into an agreement to sell its undivided 1/12th interest in the Bistineau Storage Facility in Louisiana for approximately $19 million. Until such time as the sale closes, the Partnership will continue to utilize this facility to provide storage services to its customers. Subject to approval by FERC, the Partnership anticipates closing the sale on April 1, 2020.

(15) Equity-Based Compensation

The following table summarizes the Partnership’s equity-based compensation expense for the three and nine months ended September 30, 2019 and 2018 related to performance units, restricted units and phantom units for the Partnership’s employees and independent directors:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018

	(In millions)
Performance units	$	3	$	2	$	8	$	7
Restricted units	—		—		—		1
Phantom units	1		2		5		4
Total compensation expense	$	4	$	4	$	13	$	12

The following table presents the assumptions related to the performance share units granted in 2019.



	2019
Number of units granted	610,170
Fair value of units granted	$	19.95
Expected distribution yield	8.38		%
Expected price volatility	34.2		%
Risk-free interest rate	2.54		%
Expected life of units (in years)	3

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The following table presents the number of phantom units granted and the grant date fair value related to the phantom units granted in 2019.



	2019
Phantom Units granted	603,571
Fair value of phantom units granted	$14.04 - $15.04

Units Outstanding

A summary of the activity for the Partnership’s performance units and phantom units applicable to the Partnership’s employees at September 30, 2019 and changes during 2019 are shown in the following table.



	Performance Units					Phantom Units
	Number of Units			Weighted Average Grant-Date Fair Value, Per Unit		Number of Units			Weighted Average Grant-Date Fair Value, Per Unit

	(In millions, except unit data)
Units outstanding at December 31, 2018	2,109,835			$	14.33	1,447,590			$	12.38
Granted ⁽¹⁾	610,170			19.95		603,571			15.00
Vested ⁽²⁾	(1,162,512		)	11.01		(589,481		)	8.51
Forfeited	(53,875		)	18.70		(59,004		)	14.81
Units outstanding at September 30, 2019	1,503,618			$	19.02	1,402,676			$	15.03
Aggregate intrinsic value of units outstanding at September 30, 2019	$	18				$	17

_____________________


(1)	Performance units 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% to 200% of the target.

(2)

Performance units vested as of September 30, 2019 include 1,103,761 and 26,986 units from 2016 grants, which were approved by the Board of Directors in 2016 and paid out at 200%, or 2,207,522 units on March 1, 2019 and 53,972 units on September 6, 2019, based on the level of achievement of a performance goal established by the Board of Directors over the performance period of January 1, 2016 through December 31, 2018.

Unrecognized Compensation Cost

A summary of the Partnership’s unrecognized compensation cost for its non-vested performance 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, 2019
	Unrecognized Compensation Cost (In millions)		Weighted Average Period for Recognition (In years)
Performance Units	$	15	1.54
Phantom Units	11		1.56
Total	$	26

As of September 30, 2019, there were 6,284,006 units available for issuance under the long-term incentive plan.

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(16) Reportable Segments

The Partnership’s determination of reportable segments considers the strategic operating units under which it manages sales, allocates resources and assesses performance of various products and services to customers in differing regulatory environments. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies excerpt in the Partnership’s audited 2018 consolidated financial statements included in the Annual Report. The Partnership uses operating income as the measure of profit or loss for its reportable segments.

The Partnership’s assets and operations are organized into two reportable segments: (i) gathering and processing, which primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers, and (ii) transportation and storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to our producer, power plant, LDC and industrial end-user customers.

Financial data for reportable segments are as follows:



Three Months Ended September 30, 2019	Gathering and Processing		Transportation ⁽¹⁾and Storage		Eliminations			Total

	(In millions)
Product sales	$	294	$	100	$	(74	)	$	320
Service revenues	248		134		(3		)	379
Total Revenues	542		234		(77		)	699
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	238		102		(77		)	263
Operation and maintenance, General and administrative	79		57		—			136
Depreciation and amortization	77		31		—			108
Taxes other than income tax	10		7		—			17
Operating income	$	138	$	37	$	—		$	175
Total Assets	$	9,902	$	5,839	$	(3,306	)	$	12,435
Capital expenditures	$	70	$	31	$	—		$	101


Three Months Ended September 30, 2018	Gathering and Processing		Transportation ⁽¹⁾and Storage		Eliminations			Total

	(In millions)
Product sales	$	528	$	153	$	(128	)	$	553
Service revenues	250		128		(3		)	375
Total Revenues	778		281		(131		)	928
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	493		152		(129		)	516
Operation and maintenance, General and administrative	78		48		—			126
Depreciation and amortization	66		34		—			100
Taxes other than income tax	9		6		—			15
Operating income	$	132	$	41	$	(2	)	$	171
Total assets as of December 31, 2018	$	9,874	$	5,805	$	(3,235	)	$	12,444
Capital expenditures	$	125	$	51	$	—		$	176

_____________________


(1)	See Note 8 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and nine months ended September 30, 2019 and 2018.

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Nine Months Ended September 30, 2019	Gathering and Processing		Transportation ⁽¹⁾ and Storage		Eliminations			Total

	(In millions)
Product sales	$	1,096	$	381	$	(321	)	$	1,156
Service revenues	663		421		(11		)	1,073
Total Revenues	1,759		802		(332		)	2,229
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	895		394		(331		)	958
Operation and maintenance, General and administrative	238		152		(1		)	389
Depreciation and amortization	229		94		—			323
Taxes other than income tax	31		21		—			52
Operating income	$	366	$	141	$	—		$	507
Total Assets	$	9,902	$	5,839	$	(3,306	)	$	12,435
Capital expenditures	$	267	$	86	$	—		$	353


Nine Months Ended September 30, 2018	Gathering and Processing		Transportation ⁽¹⁾ and Storage		Eliminations			Total

	(In millions)
Product sales	$	1,411	$	442	$	(356	)	$	1,497
Service revenues	599		395		(10		)	984
Total Revenues	2,010		837		(366		)	2,481
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	1,262		438		(365		)	1,335
Operation and maintenance, General and administrative	230		141		(1		)	370
Depreciation and amortization	191		101		—			292
Taxes other than income tax	29		19		—			48
Operating income	$	298	$	138	$	—		$	436
Total assets as of December 31, 2018	$	9,874	$	5,805	$	(3,235	)	$	12,444
Capital expenditures	$	416	$	135	$	—		$	551

_____________________


(1)	See Note 8 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and nine months ended September 30, 2019 and 2018.

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 consolidated financial statements and the related notes included herein and our audited consolidated financial statements for the year ended December 31, 2018, included in our Annual Report. 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.

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Overview

Enable Midstream Partners, LP is a Delaware limited partnership formed in May 2013 to own, operate and develop midstream energy infrastructure assets strategically located to serve our customers. We completed our initial public offering in April 2014, and we are traded on the New York Stock Exchange under the symbol “ENBL.” Our general partner is owned by CenterPoint Energy and OGE Energy. In this report, the terms “Partnership” and “Registrant” as well as the terms “our,” “we,” “us” and “its,” are sometimes used as abbreviated references to Enable Midstream Partners, LP together with its consolidated subsidiaries.

Our assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. Our gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers and crude oil, condensate and produced water gathering services to our producer and refiner customers. Our transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers.

Our natural gas gathering and processing assets are primarily located in Oklahoma, Texas, Arkansas and Louisiana and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Our crude oil gathering assets are located in Oklahoma and North Dakota and serve crude oil production in the Anadarko and Williston Basins. Our natural gas transportation and storage assets consist primarily of an interstate pipeline system extending from western Oklahoma and the Texas Panhandle to Louisiana, an interstate pipeline system extending from Louisiana to Illinois, an intrastate pipeline system in Oklahoma and our investment in SESH, an interstate pipeline extending from Louisiana to Alabama.

We expect our business to continue to be affected by the key trends included in our Annual Report, as well as the recent developments discussed herein. Our expectations are based on assumptions made by us and information currently available to us. 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.

Our primary business objective is to increase the cash available for distribution to our unitholders over time while maintaining our financial flexibility. Our business strategies for achieving this objective include capitalizing on organic growth opportunities associated with our strategically located assets, growing through accretive acquisitions, maintaining strong customer relationships to attract new volumes and expand beyond our existing asset footprint and business lines, and continuing to minimize direct commodity price exposure through fee-based contracts. As part of these efforts, we continuously engage in discussions with new and existing customers regarding potential projects to develop new midstream assets to support their needs as well as discussions with potential counterparties regarding opportunities to purchase or invest in complementary assets in new operating areas or midstream business lines. These growth, acquisition and development efforts often involve assets which, if acquired or constructed, could have a material effect on our financial condition and results of operations.

Recent Developments

Our Sponsors

CenterPoint Energy and OGE Energy each own a significant interest in us. In the first quarter of 2016, CenterPoint Energy announced that it was evaluating strategic alternatives for its investment in the Partnership. In the first quarter of 2018, CenterPoint Energy disclosed it had decided not to pursue a sale or spin-off qualifying under Section 355 of the U.S. Internal Revenue Code at that time and that, while a transaction for all its interests in the Partnership was not viable at that time, it may pursue a transaction if it becomes viable in the future. CenterPoint Energy also disclosed that it may reduce its investment in the Partnership through a sale of all or a portion of the Partnership common units it owns in the public equity markets or otherwise, subject to certain limitations. On August 5, 2019, CenterPoint filed Schedule 13D/A that disclosed that it has no intention to reduce its ownership of Common Units in the Partnership and currently plans to hold such Common Units and to utilize any cash distributions received on such Common Units to finance a portion of CenterPoint’s capital expenditure program.

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Commercial Update

Transportation and Storage Agreements with CenterPoint Energy

EGT provides natural gas transportation and storage services to CenterPoint Energy's LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas under a combination of contracts that include the following types of services: firm transportation, firm transportation with seasonal demand, firm storage, no-notice transportation with storage and maximum rate firm transportation. These contracts are in effect through March 31, 2021. CenterPoint’s LDCs have received the required regulatory approvals to extend transportation and storage contracts with EGT. The term for the transportation and storage services provided to CenterPoint Energy’s LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas is expected to be extended beyond March 31, 2021, pursuant to the terms of the approved contracts.

Sale of Interest in Bistineau Storage Facility

Regulatory Update

FERC Revised Policy Statement on Treatment of Income Taxes

The regulation of midstream energy infrastructure assets has a significant impact on our business. For example, our interstate natural gas transportation and storage assets are subject to regulation by FERC under the Natural Gas Act (NGA). In March 2018, FERC announced a Revised Policy Statement on Treatment of Income Taxes stating that it would no longer allow pipelines organized as a master limited partnership to recover an income tax allowance in their cost-of-service rates. In July 2018, FERC issued new regulations which required all FERC-regulated natural gas pipelines to make a one-time Form No. 501-G filing providing certain financial information and to select one of four options: (i) file a limited NGA Section 4 filing reducing its rates only as required in relation to the Tax Cuts and Jobs Act of 2017 and the Revised Policy Statement, (ii) commit to filing a general NGA Section 4 rate case in the near future, (iii) file a statement explaining why an adjustment to rates is not needed, or (iv) take no other action. In October 2018, EGT filed its Form No. 501-G and filed a statement that it intended to take no other action. On March 8, 2019, FERC terminated EGT’s 501-G proceeding and required no other action. MRT did not file a FERC Form No. 501-G because MRT had filed a general NGA Section 4 rate case in June 2018.

MRT Rate Case

In June 2018, MRT filed a general NGA rate case. MRT began collecting those rates, subject to refund, on January 1, 2019. On June 17, 2019, FERC set the rate case for a hearing to begin in January 2020, however the procedural schedule was subsequently suspended. On November 5, 2019, MRT filed a proposed settlement for the rate case as to customers holding 97% of MRT’s firm subscribed transportation capacity and asking the presiding administrative law judge to certify the proposed settlement to FERC for approval. In addition to settling on rates that the parties could accept, the settlements include as one element the extension of contracts by most of the settling parties for terms that will end in 2024.

On October 30, 2019, MRT filed a second rate case with FERC. The second rate case seeks increased rates to reflect the impacts of the turnback of previously contracted firm transportation and firm storage capacity primarily by MRT’s largest customer, Spire. The second rate case was necessary because the settlement of the first rate case was not unanimous, requiring that new maximum rates be established for the non-settling parties reflecting the turnback of capacity. On November 5, 2019, MRT filed a proposed settlement for the second rate case as to additional customers. The FERC may accept or reject the proposed settlements in the first and second rate cases as to all of the parties, or may accept the settlements as to the settling parties and set one or both of the rate hearing as to the non-settling parties.

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Enable Gulf Run Certificate Pre-Filing Process

On April 12, 2019, FERC accepted EGR and EGT into the pre-filing process in connection with their prospective applications for certificate to construct, operate and maintain natural gas pipeline facilities. Using the pre-filing procedures should enable more efficient and expeditious actions by FERC on EGR’s and EGT’s certificate applications allowing these entities, in advance of filing certificate applications with FERC, to engage stakeholders in the identification and resolution of concerns and to engage a consultant to work at FERC’s direction to perform an environmental impact assessment.

PHMSA Update

In addition to the regulation of our interstate natural gas transportation and storage assets by FERC, our midstream energy infrastructure assets are subject to regulation by various federal and state agencies, including Department of Transportation’s Pipeline and Hazardous Materials Safety Administration. On October 1, 2019, PHMSA published three final rules on pipeline safety: Enhanced Emergency Order Procedures; Safety of Hazardous Liquid Pipelines; and Safety of Gas Transmission Pipelines: Maximum Allowable Operating Pressure Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments. The Enhanced Emergency Order Procedures rule, which is effective on December 2, 2019, implements an existing statutory authorization for PHMSA to issue emergency orders related to pipeline safety if an unsafe condition or practice, or a combination of unsafe conditions and practices, constitutes, or is causing an imminent hazard. The Safety of Hazardous Liquid Pipelines rule, which goes into effect on July 1, 2020, expands PHMSA’s regulation of the safety of hazardous liquid pipelines by extending reporting requirements to certain hazardous liquid, gravity flow and rural gathering pipelines, establishing new requirements for integrity management programs for hazardous liquid pipelines in High Consequence Areas (HCAs) and certain onshore hazardous liquid pipelines located outside of HCAs, extending leak detection requirements to all non-gathering hazardous liquid pipelines, requiring new or replaced pipelines to be designed and built to accommodate in-line inspection devices, and requiring operators to inspect affected pipelines following an extreme weather event or natural disaster so they may address any resulting damage. The Safety of Gas Transmissions Pipelines rule, which goes into effect on July 1, 2020, requires operators of certain gas transmission pipelines that have been tested or that have inadequate records to determine the material strength of their lines by reconfirming the Maximum Allowable Operating Pressure, and establishes a new Moderate Consequence Area for determining regulatory requirements for gas transmission pipeline segments outside of HCAs. The rule also establishes new requirements for conducting baseline assessments incorporates into the regulations industry standards and guidelines regarding design, construction and in-line inspections, and new requirements for data integration and risk analysis in integrity management programs, including seismicity, manufacturing and construction defects, and crack and crack-like defects, and includes several requirements that allow operators to notify PHMSA of proposed alternative approaches to achieving the objectives of the minimum safety standards. We are in the process of assessing the impact of these rules on our future costs of operations and revenue from operations.

In addition to the Safety of Gas Transmission Pipelines rule, PHMSA is working on two additional rules related to gas pipeline safety. First, the rule entitled “Pipeline Safety: Safety of Gas Transmission Pipelines, Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments” is expected to amend the pipeline safety regulations relevant to gas transmission pipelines by adjusting the repair criteria for pipelines in HCAs and creating new criteria for pipelines in non-HCAs, requiring the inspection of pipelines following extreme events, requiring safety features on in-line inspection tool launchers and receivers, updating and bolstering pipeline corrosion control, codifying a management of change process, clarifying certain integrity management provisions, and strengthening integrity management assessment requirements. Second, the rule entitled “Safety of Gas Gathering Pipelines,” is expected to require all gas gathering pipeline operators to report incidents and annual pipeline data and to extend regulatory safety requirements to certain gas gathering pipelines in rural areas. These two additional rulemakings are expected to be issued by mid-2020. We are not be able to assess the impact of these rules on our future costs of operations and revenue from operations until they are finalized and published by PHMSA. These anticipated rulemakings, as well as any future pipeline safety legislation and implementing regulations, could have a material effect on our future costs of operations and revenue from operations.

Liquidity Update

2029 Senior Notes

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Term Loan Agreement

On January 29, 2019, the Partnership entered into a term loan facility, providing for an unsecured three-year $1 billion term loan agreement. On September 16, 2019, the Partnership repaid $200 million of borrowings outstanding under the 2019 Term Loan Agreement. For more information, please see Note 9 of the Notes to Condensed Consolidated Financial Statements.

Results of Operations

The following tables summarize the key components of our results of operations for the three and nine months ended September 30, 2019 and 2018.



Three Months Ended September 30, 2019	Gathering and Processing		Transportation and Storage		Eliminations			Enable Midstream Partners, LP

	(In millions)
Product sales	$	294	$	100	$	(74	)	$	320
Service revenues	248		134		(3		)	379
Total Revenues	542		234		(77		)	699
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	238		102		(77		)	263
Gross margin ⁽¹⁾	304		132		—			436
Operation and maintenance, General and administrative	79		57		—			136
Depreciation and amortization	77		31		—			108
Taxes other than income tax	10		7		—			17
Operating income	$	138	$	37	$	—		$	175
Equity in earnings of equity method affiliate	$	—	$	5	$	—		$	5



Three Months Ended September 30, 2018	Gathering and Processing		Transportation and Storage		Eliminations			Enable Midstream Partners, LP

	(In millions)
Product sales	$	528	$	153	$	(128	)	$	553
Service revenues	250		128		(3		)	375
Total Revenues	778		281		(131		)	928
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	493		152		(129		)	516
Gross margin ⁽¹⁾	285		129		(2		)	412
Operation and maintenance, General and administrative	78		48		—			126
Depreciation and amortization	66		34		—			100
Taxes other than income tax	9		6		—			15
Operating income	$	132	$	41	$	(2	)	$	171
Equity in earnings of equity method affiliate	$	—	$	7	$	—		$	7

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Nine Months Ended September 30, 2019	Gathering and Processing		Transportation and Storage		Eliminations			Enable Midstream Partners, LP

	(In millions)
Product sales	$	1,096	$	381	$	(321	)	$	1,156
Service revenues	663		421		(11		)	1,073
Total Revenues	1,759		802		(332		)	2,229
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	895		394		(331		)	958
Gross margin ⁽¹⁾	864		408		(1		)	1,271
Operation and maintenance, General and administrative	238		152		(1		)	389
Depreciation and amortization	229		94		—			323
Taxes other than income tax	31		21		—			52
Operating income	$	366	$	141	$	—		$	507
Equity in earnings of equity method affiliate	$	—	$	12	$	—		$	12



Nine Months Ended September 30, 2018	Gathering and Processing		Transportation and Storage		Eliminations			Enable Midstream Partners, LP

	(In millions)
Product sales	$	1,411	$	442	$	(356	)	$	1,497
Service revenues	599		395		(10		)	984
Total Revenues	2,010		837		(366		)	2,481
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	1,262		438		(365		)	1,335
Gross margin ⁽¹⁾	748		399		(1		)	1,146
Operation and maintenance, General and administrative	230		141		(1		)	370
Depreciation and amortization	191		101		—			292
Taxes other than income tax	29		19		—			48
Operating income	$	298	$	138	$	—		$	436
Equity in earnings of equity method affiliate	$	—	$	20	$	—		$	20

_____________________


(1)	Gross margin is a non-GAAP measure and is reconciled to its most directly comparable financial measures calculated and presented below under the caption Reconciliations of Non-GAAP Financial Measures.

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	Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018

Operating Data:
Natural gas gathered volumes—TBtu	411	424	1,240	1,212
Natural gas gathered volumes—TBtu/d	4.47	4.61	4.54	4.44
Natural gas processed volumes—TBtu ⁽¹⁾	229	230	689	641
Natural gas processed volumes—TBtu/d ⁽¹⁾	2.49	2.50	2.52	2.35
NGLs produced—MBbl/d ⁽¹⁾⁽²⁾	117.78	142.00	128.62	127.92
NGLs sold—MBbl/d ⁽²⁾⁽³⁾	118.29	146.29	131.49	130.18
Condensate sold—MBbl/d	6.16	4.25	7.36	5.97
Crude oil and condensate gathered volumes—MBbl/d	132.99	31.87	120.17	29.11
Transported volumes—TBtu	549	497	1,703	1,502
Transported volumes—TBtu/d	5.97	5.40	6.22	5.49
Interstate firm contracted capacity—Bcf/d	6.02	5.76	6.31	5.84
Intrastate average deliveries—TBtu/d	2.10	2.02	2.16	2.04

_____________________


(1)	Includes volumes under third-party processing arrangements.


(2)	Excludes condensate.


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



	Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018
Anadarko
Gathered volumes—TBtu/d	2.27	2.31	2.32	2.16
Natural gas processed volumes—TBtu/d ⁽¹⁾	2.04	2.08	2.07	1.94
NGLs produced—MBbl/d ⁽¹⁾⁽²⁾	103.53	124.80	111.99	111.74
Crude oil and condensate gathered volumes—MBbl/d	91.58	—	82.75	—
Arkoma
Gathered volumes—TBtu/d	0.46	0.56	0.48	0.55
Natural gas processed volumes—TBtu/d ⁽¹⁾	0.10	0.10	0.10	0.10
NGLs produced—MBbl/d ⁽¹⁾⁽²⁾	4.42	7.04	5.89	6.54
Ark-La-Tex
Gathered volumes—TBtu/d	1.74	1.74	1.74	1.73
Natural gas processed volumes—TBtu/d	0.35	0.32	0.35	0.31
NGLs produced—MBbl/d ⁽¹⁾⁽²⁾	9.83	10.16	10.74	9.64
Williston
Crude oil gathered volumes—MBbl/d	41.41	31.87	37.42	29.11

_____________________


(1)	Includes volumes under third-party processing arrangements.


(2)	Excludes condensate.

Gathering and Processing

Three months ended September 30, 2019 compared to three months ended September 30, 2018. Our gathering and processing segment reported operating income of $138 million for the three months ended September 30, 2019 compared to operating income of $132 million for the three months ended September 30, 2018. The difference of $6 million in operating income between periods was primarily due to a $19 million increase in gross margin, an $11 million increase in depreciation and amortization, a $1 million increase in taxes other than income and a $1 million increase in operation and maintenance and general and administrative expenses during the three months ended September 30, 2019.

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Our gathering and processing segment revenues decreased $236 million. The decrease was primarily due to the following:

Product Sales:


•	revenues from NGL sales decreased $247 million primarily due to lower sales volumes from lower recoveries of ethane, a decrease in the average realized sales price from lower average market prices for all NGL products, and higher volumes subject to fee deductions for NGLs sold under certain third-party processing arrangements and


•	revenues from natural gas sales decreased $18 million due to lower average realized natural gas sales prices and lower sales volumes.

These decreases were partially offset by:


•	realized gains on natural gas, condensate and NGL derivatives increased $17 million and


•	changes in the fair value of natural gas, condensate and NGL derivatives increased $14 million.

Service Revenues:


•	processing service revenues decreased $22 million due to lower consideration received from percent-of-proceeds, percent-of-liquids and keep-whole processing arrangements due to a decrease in the average realized price.

This decrease was partially offset by:


•	crude oil, condensate and produced water gathering revenues increased $12 million primarily due to an increase related to the November 2018 acquisition of EOCS and an increase in volumes in the Williston Basin, partially offset by lower average rates and


•	natural gas gathering revenues increased $8 million due to higher fees in the Anadarko Basin, partially offset by lower gathered volumes and lower shortfall payments associated with the expiration of minimum volume commitments in the Arkoma Basin.

Our gathering and processing segment gross margin increased $19 million. The increase was primarily due to the following:


•	realized gains on natural gas, condensate and NGL derivatives increased $17 million,


•	changes in the fair value of natural gas, condensate and NGL derivatives increased $14 million,


•	crude oil, condensate and produced water gathering revenues increased $12 million primarily due to an increase related to the November 2018 acquisition of EOCS and an increase in volumes in the Williston Basin, partially offset by lower average rates,


•	natural gas gathering fees increased $8 million due to higher fees in the Anadarko Basin, partially offset by lower gathered volumes and lower shortfall payments associated with the expiration of minimum volume commitments in the Arkoma Basin, and


•	revenues from natural gas sales less the cost of natural gas increased approximately $3 million due to lower operational gas purchases, partially offset by lower average natural gas sales prices.

These increases were partially offset by:


•	processing service fees decreased $22 million due to lower consideration received from percent-of-proceeds, percent-of-liquids and keep-whole processing arrangements due to a decrease in the average realized price and


•	revenues from NGL sales less the cost of NGLs decreased $13 million due to lower average realized sales prices and lower processed volumes.

Our gathering and processing segment operation and maintenance and general and administrative expenses increased $1 million. The increase was primarily due to a $4 million increase in payroll-related costs and a $1 million increase due to lower capitalized overhead costs. These were partially offset by a $4 million decrease in materials and supplies and contract services expenses primarily due to timing of operation and maintenance activities and a $1 million decrease in equipment rentals due to a decrease in compressor rentals.

Our gathering and processing segment depreciation and amortization increased $11 million primarily due to a $5 million increase in depreciation from the implementation of new rates from the 2019 depreciation study, $3 million of amortization of customer intangibles acquired as part of the acquisition of EOCS in the fourth quarter of 2018 and an increase in depreciation of $3 million related to other additional assets placed in service.

Our gathering and processing segment taxes other than income tax increased $1 million due to higher accrued ad valorem taxes due to additional assets placed in service.

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Nine months ended September 30, 2019 compared to nine months ended September 30, 2018. Our gathering and processing segment reported operating income of $366 million for the nine months ended September 30, 2019 compared to operating income of $298 million for the nine months ended September 30, 2018. The difference of $68 million in operating income between periods was primarily due to a $116 million increase in gross margin. This was partially offset by a $8 million increase in operation and maintenance and general and administrative expenses, a $38 million increase in depreciation and amortization and a $2 million increase in taxes other than income tax during the nine months ended September 30, 2019.

Our gathering and processing segment revenues decreased $251 million. The decrease was primarily due to the following:

Product Sales:


•	revenues from NGL sales decreased $361 million primarily due to a decrease in the average realized sales price from lower average market prices for all NGL products and higher volumes subject to fee deductions for NGLs sold under certain third-party processing arrangements, partially offset by higher processed volumes and


•	revenues from natural gas sales decreased $8 million due to lower average natural gas sales prices, partially offset by higher sales volumes.

These decreases were partially offset by:


•	realized gains on natural gas, condensate and NGL derivatives increased $31 million and


•	changes in the fair value of natural gas, condensate and NGL derivatives increased $23 million.

Service Revenues:


•	processing service revenues decreased $17 million due to lower consideration received from percent-of-proceeds, percent-of-liquids and keep-whole processing arrangements due to a decrease in the average realized price, partially offset by higher processed volumes in the Anadarko and Ark-La-Tex Basins.

This decrease was offset by:


•	natural gas gathering revenues increased $50 million due to higher fees and gathered volumes in the Anadarko Basin, partially offset by lower gathered volumes and lower shortfall payments associated with the expiration of minimum volume commitments in the Arkoma Basin,


•	crude oil, condensate and produced water gathering revenues increased $30 million primarily due to an increase related to the November 2018 acquisition of EOCS and an increase in volumes in the Williston Basin, partially offset by lower average rates, and


•	a $1 million increase in intercompany management fees.

Our gathering and processing segment gross margin increased $116 million. The increase was primarily due to the following:


•	natural gas gathering fees increased $50 million due to higher fees and gathered volumes in the Anadarko Basin, partially offset by lower gathered volumes and lower shortfall payments associated with the expiration of minimum volume commitments in the Arkoma Basin,


•	crude oil, condensate and produced water gathering revenues increased $30 million primarily due to an increase related to the November 2018 acquisition of EOCS and an increase in volumes in the Williston Basin, partially offset by lower average rates,


•	realized gains on natural gas, condensate and NGL derivatives increased $31 million,


•	changes in the fair value of natural gas, condensate and NGL derivatives increased $23 million, and


•	a $1 million increase in intercompany management fees.

These increases were partially offset by:


•	processing service fees decreased $17 million due to lower consideration received from percent-of-proceeds, percent-of-liquids and keep-whole processing arrangements due to a decrease in the average realized price, partially offset by higher processed volumes in the Anadarko and Ark-La-Tex Basins,


•	revenues from NGL sales less the cost of NGLs decreased $1 million due to lower average sales prices for all NGL products, partially offset by higher processed volumes, and


•	revenues from natural gas sales less the cost of natural gas decreased approximately $1 million due to lower average natural gas sales prices, partially offset by higher sales volumes.

Our gathering and processing segment operation and maintenance and general and administrative expenses increased $8 million. The increase was primarily due to an $8 million increase in payroll-related costs, a $2 million increase in utilities and insurance as a result of additional assets in service, and a $2 million increase due to lower capitalized overhead costs. These

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increases were partially offset by a $4 million decrease in materials and supplies and contract services expenses primarily due to timing of operation and maintenance activities.

Our gathering and processing segment depreciation and amortization increased $38 million primarily due to an increase of $15 million in depreciation from the implementation of new rates from the 2019 depreciation study, $13 million of amortization of customer intangibles acquired as part of the acquisition of EOCS in the fourth quarter of 2018 and a $10 million increase in depreciation related to other additional assets placed in service.

Our gathering and processing segment taxes other than income tax increased $2 million due to higher accrued ad valorem taxes due to additional assets placed in service.

Transportation and Storage

Three months ended September 30, 2019 compared to three months ended September 30, 2018. Our transportation and storage segment reported operating income of $37 million for the three months ended September 30, 2019 compared to $41 million for the three months ended September 30, 2018. The difference of $4 million in operating income between periods was driven by a $9 million increase in operation and maintenance and general and administrative expenses and a $1 million increase in taxes other than income taxes, partially offset by a $3 million increase in gross margin and a $3 million decrease in depreciation and amortization for the three months ended September 30, 2019.

Our transportation and storage segment revenues decreased $47 million. The decrease was primarily due to the following:

Product Sales:


•	revenues from natural gas sales decreased $51 million primarily due to lower sales volumes and lower average sales prices and


•	revenues from NGL sales decreased $2 million due to lower average sales prices, partially offset by higher volumes.

Service Revenues:


•	firm transportation and storage services increased $5 million due to new intrastate and interstate transportation contracts and


•	volume-dependent transportation revenues increased $1 million due to an increase in off-system transportation due to new interstate contracts.

Our transportation and storage segment gross margin increased $3 million. The increase was primarily due to the following:


•	firm transportation and storage services increased $5 million due to new intrastate and interstate transportation contracts and


•	volume-dependent transportation revenues increased $1 million due to an increase in off-system transportation due to new interstate contracts.

These increases were partially offset by:

•system management activities decreased $2 million and


•	revenues from NGL sales less the cost of NGLs decreased $1 million due to a decrease in average NGL prices, partially offset by higher volumes.

Our transportation and storage segment operation and maintenance and general and administrative expenses increased $9 million. This increase was primarily driven by a $4 million increase in reserves for claims settlement costs, a $3 million loss on retirement of assets during the third quarter 2019 with no comparable item during the third quarter 2018, a $1 million increase in materials and supplies and outside services due to pipeline safety and storage integrity work under our pipeline safety program and to comply with certain PHMSA regulations and a $1 million increase in payroll-related costs.

Our transportation and storage segment depreciation and amortization decreased $3 million primarily due to a $3 million decrease in depreciation from the implementation of new intrastate natural gas pipeline depreciation rates from the 2019 depreciation study.

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Nine Months Ended September 30, 2019 compared to nine months ended September 30, 2018. Our transportation and storage segment reported operating income of $141 million for the nine months ended September 30, 2019 compared to operating income of $138 million for the nine months ended September 30, 2018. The difference of $3 million in operating income between periods was primarily due to a $9 million increase in gross margin and a $7 million decrease in depreciation and amortization, partially offset by a $11 million increase in operation and maintenance and general and administrative expenses and a $2 million increase in taxes other than income taxes for the nine months ended September 30, 2019.

Our transportation and storage segment revenues decreased $35 million. The decrease was primarily due to the following:

Product Sales:


•	revenues from natural gas sales decreased $55 million primarily due to lower average sales prices and lower volumes,


•	revenues from NGL sales decreased $4 million due to lower average sales prices, partially offset by an increase in volumes and


•	realized losses on natural gas derivatives increased $4 million.

These decreases were partially offset by:


•	changes in the fair value of natural gas derivatives increased $2 million.

Service Revenues:


•	firm transportation and storage services increased $26 million due to new intrastate and interstate transportation contracts.

Our transportation and storage segment gross margin increased $9 million. The increase was primarily due to the following:


•	firm transportation and storage services increased $26 million due to new intrastate and interstate transportation contracts and


•	changes in the fair value of natural gas derivatives increased $2 million.

These increases were partially offset by:


•	system management activities decreased $7 million,


•	realized losses on natural gas derivatives increased $4 million,


•	storage decreased $4 million primarily due to a lower of cost or net realizable value adjustment on natural gas inventory, and


•	revenues from NGL sales less the cost of NGLs decreased $4 million due to a decrease in average NGL prices, partially offset by higher volumes.

Our transportation and storage segment operation and maintenance and general and administrative expenses increased $11 million. This increase was primarily driven by a $4 million increase in reserves for claims settlement costs, a $4 million loss on retirement of assets during 2019 with no comparable item in 2018, a $3 million increase in materials and supplies and outside services due to pipeline safety and storage integrity work under our pipeline safety program and to comply with certain PHMSA regulations, a $1 million increase in payroll-related costs, and a $1 million increase in intercompany management fees. These increases were partially offset by a $2 million decrease in information-technology related costs.

Our transportation and storage segment depreciation and amortization decreased $7 million primarily due to a decrease of $7 million in depreciation from the implementation of new intrastate natural gas pipeline depreciation rates from the 2019 depreciation study.

Our transportation and storage segment taxes other than income tax increased $2 million due to higher accrued ad valorem taxes due to additional assets placed in service and higher net operating incomes.

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Condensed Consolidated Interim Information



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018

	(In millions)
Operating Income	$	175		$	171		$	507		$	436
Other Income (Expense):
Interest expense	(48		)	(40		)	(142		)	(109		)
Equity in earnings of equity method affiliate	5			7			12			20
Other, net	1			1			2			1
Total Other Expense	(42		)	(32		)	(128		)	(88		)
Income Before Income Taxes	133			139			379			348
Income tax benefit	—			—			(1		)	—
Net Income	$	133		$	139		$	380		$	348
Less: Net income attributable to noncontrolling interest	1			1			2			1
Net Income Attributable to Limited Partners	$	132		$	138		$	378		$	347
Less: Series A Preferred Unit distributions	9			9			27			27
Net Income Attributable to Common Units	$	123		$	129		$	351		$	320

Three Months Ended September 30, 2019 compared to Three Months Ended September 30, 2018

Net Income Attributable to Limited Partners. We reported net income attributable to limited partners of $132 million in the three months ended September 30, 2019 compared to net income attributable to limited partners of $138 million in the three months ended September 30, 2018. The decrease in net income attributable to limited partners of $6 million was primarily due to an increase in interest expense of $8 million and a decrease in equity in earnings of equity method affiliate of $2 million, partially offset by an increase in operating income of $4 million in the three months ended September 30, 2019.

Equity in Earnings of Equity Method Affiliate. Equity in earnings of equity method affiliate decreased $2 million primarily due to an increase in ad valorem taxes of approximately $1 million driven by the expiration of a property tax credit and an increase of $1 million in operating expenses.

Interest Expense. Interest expense increased $8 million primarily due to an increase in principal amounts and interest rates on the Partnership’s outstanding debt.

Nine Months Ended September 30, 2019 compared to Nine Months Ended September 30, 2018

Net Income Attributable to Limited Partners. We reported net income attributable to limited partners of $378 million in the nine months ended September 30, 2019 compared to net income attributable to limited partners of $347 million in the nine months ended September 30, 2018. The increase in net income attributable to limited partners of $31 million was primarily attributable to an increase in operating income of $71 million, partially offset by an increase in interest expense of $33 million and a decrease in equity in earnings of equity method affiliate of $8 million in the nine months ended September 30, 2019.

Equity in Earnings of Equity Method Affiliate. Equity in earnings of equity method affiliate decreased $8 million primarily due to an increase in ad valorem taxes of approximately $4 million due to the expiration of a property tax credit, a decrease of $2 million in revenues due to a reduction in firm transportation services and an increase of $2 million in operating expenses.

Interest Expense. Interest expense increased $33 million primarily due to an increase in principal amounts and interest rates on the Partnership’s outstanding debt.

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Reconciliations of Non-GAAP Financial Measures

The Partnership has included the non-GAAP financial measures Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio in this report based on information in its condensed consolidated financial statements. Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio are part of the performance measures that we use to manage the Partnership.

Provided below are reconciliations of Gross margin to total revenues, Adjusted EBITDA and DCF to net income attributable to limited partners, and Adjusted EBITDA to net cash provided by operating activities and Adjusted interest expense to interest expense, the most directly comparable GAAP financial measures, on a historical basis, as applicable, for each of the periods indicated. Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio should not be considered as alternatives to net income, operating income, total revenues, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. These non-GAAP financial measures have important limitations as analytical tools because they exclude some but not all items that affect the most directly comparable GAAP measures. Additionally, because Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio may be defined differently by other companies in the Partnership’s industry, these measures 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,
	2019		2018		2019		2018

	(In millions)
Reconciliation of Gross margin to Total Revenues:
Consolidated
Product sales	$	320	$	553	$	1,156	$	1,497
Service revenues	379		375		1,073		984
Total Revenues	699		928		2,229		2,481
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)	263		516		958		1,335
Gross margin	$	436	$	412	$	1,271	$	1,146

Reportable Segments
Gathering and Processing
Product sales	$	294	$	528	$	1,096	$	1,411
Service revenues	248		250		663		599
Total Revenues	542		778		1,759		2,010
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)	238		493		895		1,262
Gross margin	$	304	$	285	$	864	$	748

Transportation and Storage
Product sales	$	100	$	153	$	381	$	442
Service revenues	134		128		421		395
Total Revenues	234		281		802		837
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)	102		152		394		438
Gross margin	$	132	$	129	$	408	$	399

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The following table shows the components of our gross margin for the nine months ended September 30, 2019:



	Fee-Based ⁽¹⁾
	Demand		Volume- Dependent		Commodity- Based⁽¹⁾		Total
Nine Months Ended September 30, 2019
Gathering and Processing Segment	26	%	51	%	23	%	100	%
Transportation and Storage Segment	92	%	11	%	(3	)%	100	%
Partnership Weighted Average	47	%	37	%	16	%	100	%

____________________


(1)	For purposes of this table, the Partnership includes the value of all natural gas and NGL commodities received as payment as commodity-based.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018

	(In millions, except Distribution coverage ratio)
Reconciliation of Adjusted EBITDA and DCF to net income attributable to limited partners and calculation of Distribution coverage ratio:
Net income attributable to limited partners	$	132		$	138		$	378		$	347
Depreciation and amortization expense	108			100			323			292
Interest expense, net of interest income	48			40			141			109
Income tax benefit	—			—			(1		)	—
Distributions received from equity method affiliate in excess of equity earnings	(1		)	3			8			11
Non-cash equity-based compensation	4			4			13			12
Change in fair value of derivatives ⁽¹⁾	2			16			3			28
Other non-cash losses ⁽²⁾	2			—			9			4
Noncontrolling Interest Share of Adjusted EBITDA	—			—			(1		)	—
Adjusted EBITDA	$	295		$	301		$	873		$	803
Series A Preferred Unit distributions ⁽³⁾	(9		)	(9		)	(27		)	(27		)
Distributions for phantom and performance units ⁽⁴⁾	(1		)	(1		)	(10		)	(5		)
Adjusted interest expense ⁽⁵⁾	(47		)	(41		)	(143		)	(114		)
Maintenance capital expenditures	(36		)	(30		)	(86		)	(70		)
DCF	$	202		$	220		$	607		$	587

Distributions related to common unitholders ⁽⁶⁾	$	144		$	138		$	426		$	414

Distribution coverage ratio	1.40			1.60			1.42			1.42

____________________


(1)	Change in fair value of derivatives includes changes in the fair value of derivatives that are not designated as hedging instruments.


(2)	Other non-cash losses include loss on sale of assets and write-downs of materials and supplies.


(3)	This amount represents the quarterly cash distributions on the Series A Preferred Units declared for the three and nine months ended September 30, 2019 and 2018. In accordance with the Partnership Agreement, the Series A Preferred Unit distributions are deemed to have been paid out of available cash with respect to the quarter immediately preceding the quarter in which the distribution is made.


(4)	Distributions for phantom and performance units represent distribution equivalent rights paid in cash. Phantom unit distribution equivalent rights are paid during the vesting period and performance unit distribution equivalent rights are paid at vesting.


(5)	See below for a reconciliation of Adjusted interest expense to Interest expense.


(6)	Represents cash distributions declared for common units outstanding as of each respective period. Amounts for 2019 reflect estimated cash distributions for common units outstanding for the quarter ended September 30, 2019.

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018

	(In millions)
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities	$	264		$	233		$	691		$	638
Interest expense, net of interest income	48			40			141			109
Net income attributable to noncontrolling interest	(1		)	(1		)	(2		)	(1		)
Other non-cash items ⁽¹⁾	—			—			4			4
Proceeds from insurance	—			—			—			1
Changes in operating working capital which (provided) used cash:
Accounts receivable	41			46			(16		)	58
Accounts payable	(2		)	—			110			19
Other, including changes in noncurrent assets and liabilities	(56		)	(36		)	(66		)	(64		)
Return of investment in equity method affiliate	(1		)	3			8			11
Change in fair value of derivatives ⁽²⁾	2			16			3			28
Adjusted EBITDA	$	295		$	301		$	873		$	803

____________________


(1)	Other non-cash items include amortization of debt expense, discount and premium on long-term debt and write-downs of materials and supplies.


(2)	Change in fair value of derivatives includes changes in the fair value of derivatives that are not designated as hedging instruments.



	Three Months Ended September 30,					Nine Months Ended September 30,
	2019			2018		2019			2018

	(In millions)
Reconciliation of Adjusted interest expense to Interest expense:
Interest expense	$	48		$	40	$	142		$	109
Interest income	—			—		(1		)	—
Amortization of premium on long-term debt	1			1		4			4
Capitalized interest on expansion capital	—			—		1			4
Amortization of debt expense and discount	(2		)	—		(3		)	(3		)
Adjusted interest expense	$	47		$	41	$	143		$	114

Liquidity and Capital Resources

The Partnership’s principal liquidity requirements are to finance its operations, fund capital expenditures and acquisitions, make cash distributions and satisfy any indebtedness obligations. We expect that our liquidity and capital resource needs will be met by cash on hand, operating cash flow, proceeds from commercial paper issuances, borrowings under our revolving credit facility, debt issuances and the issuance of equity. However, issuances of equity or debt in the capital markets and additional credit facilities may not be available to us on acceptable terms. Access to funds obtained through the equity or debt capital markets, particularly in the energy sector, has been constrained by a variety of market factors that have hindered the ability of energy companies to raise new capital or obtain financing at acceptable terms. Factors that contribute to our ability to raise capital through these channels depend on our financial condition, credit ratings and market conditions. Our ability to generate cash flow is subject to a number of factors, some of which are beyond our control. See Part II, Item 1A. “Risk Factors” for further discussion.

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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, the level and timing of spending for maintenance and expansion activity, and the timing of debt maturities. As of September 30, 2019, we had a working capital deficit of $402 million. The deficit is primarily due to the classification of $253 million of the EOIT Senior Notes as Current portion of long-term debt as of September 30, 2019 as well as $182 million of commercial paper outstanding as of September 30, 2019. We utilize our commercial paper program and Revolving Credit Facility to manage the timing of cash flows and fund short-term working capital deficits.

Cash Flows

The following tables reflect cash flows for the applicable periods:



	Nine Months Ended September 30,
	2019			2018

	(In millions)
Net cash provided by operating activities	$	691		$	638
Net cash used in investing activities	$	(353	)	$	(531	)
Net cash used in financing activities	$	(347	)	$	(104	)

Operating Activities

The increase of $53 million or 8%, in net cash provided by operating activities for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018 was primarily driven by an increase in net income of $32 million, an increase in adjustments for non-cash items of $35 million, partially offset by a decrease of $14 million in the timing of cash receipts and disbursements and changes in other working capital assets and liabilities.

Investing Activities

The decrease of $178 million, or 34%, in net cash used in investing activities for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018 was primarily due to lower capital expenditures of $198 million, decreased proceeds from sale of asset of $7 million due to the 2018 sale of a cryogenic processing plant compared to a minor asset sale for the nine months ended September 30, 2019, proceeds from insurance of $1 million for the nine months ended September 30, 2018 with no comparable item for the nine months ended September 30, 2019, and a decrease in return of investment in equity method affiliate of $3 million, partially offset by an increase in other investing outflows of $9 million.

Financing Activities

Net cash used in financing activities increased $243 million, or 234%, for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018. Our primary financing activities consist of the following:



	Nine Months Ended September 30,
	2019			2018

	(In millions)
(Decrease) increase in short-term debt	$	(467	)	$	8
Proceeds from long-term debt, net of issuance costs	1,544			787
Repayment of 2019 Senior Notes	(500		)	—
Repayment of term loans	(200		)	(450		)
Repayments to Revolving Credit Facility	(250		)	—
Proceeds from issuance of common units, net of issuance costs	—			2
Distributions	(450		)	(442		)
Cash paid for employee equity-based compensation	(24		)	(9		)

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Please see Note 9, “Debt” in the Notes to the Unaudited Condensed Consolidated Financial Statements in Part I, Item 1. for a description of the Partnership’s debt agreements.

Sources of Liquidity

As of September 30, 2019, our sources of liquidity included:


•	cash on hand;


•	cash generated from operations;


•	proceeds from commercial paper issuances;


•	borrowings under our Revolving Credit Facility; and


•	capital raised through debt and equity markets.

ATM Program

On May 12, 2017, the Partnership entered into an ATM Equity Offering Sales Agreement, pursuant to which the Partnership may issue and sell common units having an aggregate offering price of up to $200 million, by sales methods and at prices determined by market conditions and other factors at the time of our offerings. The Partnership has no obligation to sell any common units under the ATM Program and the Partnership may suspend sales under the ATM Program at any time. During the three and nine months ended September 30, 2019 and 2018, the Partnership did not issue common units under the ATM Program. As of September 30, 2019, $197 million of common units remained available for issuance through the ATM Program.

Distributions

On November 5, 2019, the Board of Directors declared a quarterly cash distribution of $0.3305 per common unit on all of the Partnership’s outstanding common units for the period ended September 30, 2019. The distributions will be paid November 26, 2019 to unitholders of record as of the close of business on November 19, 2019. Additionally, the Board of Directors declared a quarterly cash distribution of $0.625 on the Partnership’s outstanding Series A Preferred Units. The distributions will be paid November 14, 2019 to unitholders of record as of the close of business on November 5, 2019.

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 commodities 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.

Critical Accounting Policies and Estimates

The Partnership’s critical accounting policies and estimates are described in Critical Accounting Policies and Estimates within Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 1 of the Notes to the Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” in our Annual Report. The accounting policies and estimates used in preparing our interim Condensed Consolidated Financial Statements for the three months ended September 30, 2019 are the same as those described in our Annual Report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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Commodity Price Risk

While we generate a substantial portion of our gross margin pursuant to fee-based contracts that include minimum volume commitments and/or demand fees, we are also directly and indirectly exposed to changes in the prices of natural gas, condensate and NGLs. The Partnership utilizes derivatives and forward commodity sales to mitigate the effects of price changes. We do not enter into risk management contracts for speculative purposes. For further information regarding our derivatives, see Note 10 of the Notes to the Condensed Consolidated Financial Statements.

Based on our forecasted volumes, prices and contractual arrangements, we estimate approximately 14% of our total gross margin for the twelve months ended December 31, 2019 is directly exposed to changes in commodity prices, excluding the impact of hedges and contractual floors related to commodity prices in certain agreements. Since September 30, 2019, we have entered into additional derivative contracts to further manage our exposure to commodity price risk for the three months ending December 31, 2019.

Commodity price risk is estimated as the potential loss in value resulting from a hypothetical 10% decline in prices over the next three months. Based on a sensitivity analysis, a 10% decrease in prices from forecasted levels would decrease net income by approximately $3 million for natural gas and ethane and $2 million for NGLs (other than ethane) and condensate, excluding the impact of hedges, for the remaining three months ending December 31, 2019.

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio. Our debt portfolio includes senior notes with a fixed rate of interest, which mitigates the impact of fluctuations in interest rates. Future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher interest costs. Borrowings under our Revolving Credit Facility, 2019 Term Loan Agreement and any issuances under our commercial paper program are at a variable interest rate and expose us to the risk of increasing interest rates. The Partnership utilizes derivatives to mitigate the risk of interest rate changes. We do not enter into risk management contracts for speculative purposes. For further information regarding our derivatives, see Note 10 of the Notes to the Condensed Consolidated Financial Statements.

Based upon the $982 million outstanding borrowings under commercial paper and 2019 Term Loan Agreement as of September 30, 2019, excluding the impact of hedges and holding all other variables constant, a 100 basis-point, or 1%, increase in interest rates would increase our annual interest expense by approximately $10 million. For further information regarding our interest rates, see Note 9 of the Notes to the Condensed Consolidated Financial Statements.

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 Exchange Act) as of September 30, 2019. Based on such evaluation, our management has concluded that, as of September 30, 2019, 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 Control Over Financial Reporting

There were no changes in our internal controls over financial reporting during the quarter ended September 30, 2019, that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Information regarding legal proceedings is set forth in Note 14—Commitments and Contingencies to the Partnership’s condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report on Form 10-Q and is incorporated herein by reference.

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 Annual Report. No other material changes to such risk factors have occurred during the three and nine months ended September 30, 2019.

Item 6. Exhibits

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. Management contracts and compensatory plans and arrangements are designated by a star (*).

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.

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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	Fifth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP	Registrant’s Form 8-K filed November 15, 2017	File No. 001-36413	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. 001-36413	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 February 18, 2016, by and between Enable Midstream Partners, LP and CenterPoint Energy, Inc.	Registrant’s Form 8-K filed February 19, 2016	File No. 001-36413	Exhibit 4.1
4.5	Second Supplemental Indenture, dated as of March 9, 2017, by and between Enable Midstream Partners, LP and U.S. Bank National Association, as trustee.	Registrant’s Form 8-K filed March 9, 2017	File No. 001-36413	Exhibit 4.2
4.6	Third Supplemental Indenture, dated as of May 10, 2018, by and between Enable Midstream Partners, LP and U.S. Bank National Association, as trustee.	Registrant’s Form 8-K filed May 10, 2018	File No. 001-36413	Exhibit 4.2
4.7	Fourth Supplemental Indenture, dated as of September 13, 2019, by and between Enable Midstream Partners, LP and U.S. Bank National Association, as trustee.	Registrant’s Form 8-K filed September 13, 2019	File No. 001-36413	Exhibit 4.2
+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.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report 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 6, 2019	By:	/s/ Tom Levescy
			Tom Levescy
			Senior Vice President, Chief Accounting Officer and Controller
			(Principal Accounting Officer)

Exhibit

Exhibit 31.1

CERTIFICATIONS

I, Rodney J. Sailor, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Enable Midstream Partners, LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 6, 2019




	/s/ Rodney J. Sailor
	Rodney J. Sailor
	President and Chief Executive Officer, Enable GP, LLC, the General Partner of Enable Midstream Partners, LP
	(Principal Executive Officer)

Exhibit

Exhibit 31.2

CERTIFICATIONS

I, John P. Laws, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Enable Midstream Partners, LP;


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 6, 2019




	/s/ John P. Laws
	John P. Laws
	Executive Vice President, Chief Financial Officer and Treasurer, Enable GP, LLC, the General Partner of Enable Midstream Partners, LP
	(Principal Financial Officer)

Exhibit

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Enable Midstream Partners, LP (the Partnership) on Form 10-Q for the period ended September 30, 2019, as filed with the Securities and Exchange Commission (the Report), I, Rodney J. Sailor, President and Chief Executive Officer of Enable GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: November 6, 2019




	/s/ Rodney J. Sailor
	Rodney J. Sailor
	President and Chief Executive Officer, Enable GP, LLC, the General Partner of Enable Midstream Partners, LP
	(Principal Executive Officer)

Exhibit

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Enable Midstream Partners, LP (the Partnership) on Form 10-Q for the period ended September 30, 2019, as filed with the Securities and Exchange Commission (the Report), I, John P. Laws, Executive Vice President, Chief Financial Officer, and Treasurer of Enable GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: November 6, 2019




	/s/ John P. Laws
	John P. Laws
	Executive Vice President, Chief Financial Officer and Treasurer, Enable GP, LLC, the General Partner of Enable Midstream Partners, LP
	(Principal Financial Officer)