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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	March 31, 2020



☐	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/f9ae9d94804ea1ca59ace2159a2af909-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 April 17, 2020, there were 435,448,437 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	28
Item 3. Quantitative and Qualitative Disclosures About Market Risk	41
Item 4. Controls and Procedures	42

Part II - OTHER INFORMATION
Item 1. Legal Proceedings	43
Item 1A. Risk Factors	43
Item 6. Exhibits	46

Signature	48

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 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, 2019.
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 interests 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 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, the general partner of Enable Midstream Partners, LP.
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.

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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 aggregate principal amount of EOIT’s 6.25% senior notes due 2020.
ESCP.	Enable South Central Pipeline, LLC, formerly Velocity Pipeline Partners, LLC, 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.
ETGP.	Enable Texola Gathering & Processing, LLC, formerly Align Midstream, LLC, a wholly owned subsidiary of the Partnership that provides natural gas gathering and processing services to customers in the Cotton Valley and Haynesville plays of the Ark-La-Tex Basin in Texas.
Exchange Act.	Securities Exchange Act of 1934, as amended.
FASB.	Financial Accounting Standards Board.
FERC.	Federal Energy Regulatory Commission.
GAAP.	Accounting principles generally accepted in the United States of America.
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.
LDC.	Local distribution company involved in the delivery of natural gas to consumers within a specific geographic area.
LIBOR.	London Interbank Offered Rate.
LNG.	Liquefied natural gas.
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.
NGA.	Natural Gas Act of 1938.
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.
OPEC.	Organization of the Petroleum Exporting Countries.
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 Anadarko Canadian and Kingfisher Counties.
TBtu.	Trillion British thermal units.
TBtu/d.	Trillion British thermal units per day.

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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. In particular, our statements with respect to continuity plans and preparedness measures we have implemented in response to the novel coronavirus (COVID-19) pandemic and its expected impact on our business, operations, earnings and results are forward-looking statements. 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, including the material and adverse consequences of the COVID-19 pandemic and its unfolding impact on the global and national economy;


•	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;


•	the actions of the Organization of Petroleum Exporting Countries (OPEC) and other significant producers and governments;


•	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;


•	world health events, including the ongoing spread and economic effects of COVID-19;


•	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 March 31,
	2020			2019

	(In millions, except per unit data)
Revenues (including revenues from affiliates (Note 13)):
Product sales	$	288		$	443
Service revenues	360			352
Total Revenues	648			795
Cost and Expenses (including expenses from affiliates (Note 13)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	226			378
Operation and maintenance	102			103
General and administrative	24			26
Depreciation and amortization	104			105
Impairments (Note 7)	28			—
Taxes other than income tax	18			18
Total Cost and Expenses	502			630
Operating Income	146			165
Other Income (Expense):
Interest expense	(47		)	(46		)
Equity in earnings of equity method affiliate	6			3
Total Other Expense	(41		)	(43		)
Income Before Income Tax	105			122
Income tax benefit	—			(1		)
Net Income	$	105		$	123
Less: Net (loss) income attributable to noncontrolling interest	(7		)	1
Net Income Attributable to Limited Partners	$	112		$	122
Less: Series A Preferred Unit distributions (Note 6)	9			9
Net Income Attributable to Common Units (Note 5)	$	103		$	113

Basic earnings per unit (Note 5)
Common units	$	0.24		$	0.26
Diluted earnings per unit (Note 5)
Common units	$	0.19		$	0.26

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 March 31,
	2020			2019

	(In millions)
Net income	$	105		$	123
Other comprehensive loss:
Unrealized losses on derivative instruments	(6		)	—
Reclassification of derivative losses to net income	—			—
Other comprehensive loss	(6		)	—
Comprehensive income	99			123
Less: Comprehensive (loss) income attributable to noncontrolling interest	(7		)	1
Comprehensive income attributable to Limited Partners	$	106		$	122

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ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	March 31, 2020			December 31, 2019

	(In millions)
Current Assets:
Cash and cash equivalents	$	4		$	4
Accounts receivable, net of allowance for doubtful accounts (Note 1)	192			244
Accounts receivable—affiliated companies	17			25
Inventory	43			46
Gas imbalances	36			35
Other current assets	41			35
Total current assets	333			389
Property, Plant and Equipment:
Property, plant and equipment	13,183			13,161
Less: Accumulated depreciation and amortization	2,366			2,291
Property, plant and equipment, net	10,817			10,870
Other Assets:
Intangible assets, net	585			601
Goodwill	—			12
Investment in equity method affiliate	305			309
Other, net of allowance for doubtful accounts (Note 1)	77			85
Total other assets	967			1,007
Total Assets	$	12,117		$	12,266
Current Liabilities:
Accounts payable	$	100		$	161
Accounts payable—affiliated companies	2			1
Current portion of long-term debt	—			251
Short-term debt	110			155
Taxes accrued	25			32
Gas imbalances	17			19
Other	137			161
Total current liabilities	391			780
Other Liabilities:
Accumulated deferred income taxes, net	3			4
Regulatory liabilities	24			24
Other	77			80
Total other liabilities	104			108
Long-Term Debt	4,270			3,969
Commitments and Contingencies (Note 14)
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at March 31, 2020 and December 31, 2019)	362			362
Common units (435,443,494 issued and outstanding at March 31, 2020 and 435,201,365 issued and outstanding at December 31, 2019, respectively)	6,972			7,013
Accumulated other comprehensive loss	(9		)	(3		)
Noncontrolling interest	27			37
Total Partners’ Equity	7,352			7,409
Total Liabilities and Partners’ Equity	$	12,117		$	12,266

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ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three Months Ended March 31,
	2020			2019

	(In millions)
Cash Flows from Operating Activities:
Net income	$	105		$	123
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	104			105
Deferred income taxes	—			(1		)
Impairments	28			—
Loss on sale/retirement of assets	1			1
Equity in earnings of equity method affiliate	(6		)	(3		)
Return on investment in equity method affiliate	6			3
Equity-based compensation	4			4
Changes in other assets and liabilities:
Accounts receivable, net	52			27
Accounts receivable—affiliated companies	8			2
Inventory	3			(1		)
Gas imbalance assets	(1		)	7
Other current assets	(6		)	10
Other assets	1			5
Accounts payable	(59		)	(55		)
Accounts payable—affiliated companies	1			—
Gas imbalance liabilities	(2		)	(7		)
Other current liabilities	(35		)	4
Other liabilities	(4		)	(9		)
Net cash provided by operating activities	200			215
Cash Flows from Investing Activities:
Capital expenditures	(54		)	(143		)
Return of investment in equity method affiliate	4			9
Other, net	2			(10		)
Net cash used in investing activities	(48		)	(144		)
Cash Flows from Financing Activities:
(Decrease) increase in short-term debt	(45		)	147
Proceeds from long-term debt, net of issuance costs	—			200
Repayment of long-term debt	(250		)	—
Proceeds from Revolving Credit Facility	340			—
Repayment of Revolving Credit Facility	(40		)	(250		)
Distributions to common unitholders	(144		)	(138		)
Distributions to preferred unitholders	(9		)	(9		)
Distributions to non-controlling interests	(3		)	(1		)
Cash paid for employee equity-based compensation	(1		)	(23		)
Net cash used in financing activities	(152		)	(74		)
Net Decrease in Cash, Cash Equivalents and Restricted Cash	—			(3		)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	4			22
Cash, Cash Equivalents and Restricted Cash at End of Period	$	4		$	19

See Notes to the Unaudited Condensed Consolidated Financial Statements

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ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

(Unaudited)



	Three Months Ended March 31, 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
Other comprehensive loss	—	—			—	—			—		—			—
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



	Three Months Ended March 31, 2020
	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, 2019	15	$	362		435	$	7,013		$	(3	)	$	37		$	7,409
Net income (loss)	—	9			—	103			—			(7		)	105
Other comprehensive loss	—	—			—	—			(6		)	—			(6		)
Distributions	—	(9		)	—	(144		)	—			(3		)	(156		)
Equity-based compensation, net of units for employee taxes	—	—			—	3			—			—			3
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)	—	—			—	(3		)	—			—			(3		)
Balance as of March 31, 2020	15	$	362		435	$	6,972		$	(9	)	$	27		$	7,352

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 March 31, 2020, 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 March 31, 2020, the Partnership owned a 50% interest in SESH. See Note 8 for further discussion of SESH. For the three months ended March 31, 2020, 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, the Partnership held 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, (d) acquisitions and dispositions of businesses, assets and other interests, and (e) the impact of the ongoing spread and economic effects of COVID-19 and the recent actions of Saudi Arabia and Russia which have resulted in a substantial decrease in natural gas, NGLs and crude oil prices.

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

On March 26, 2020, FERC issued an order approving MRT’s 2018 Rate Case and 2019 Rate Case settlements. As a result of the settlements, the new depreciation rates for MRT have been applied in accordance with the order. 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

The Partnership adopted ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” on January 1, 2020. Upon adoption, the Partnership recognized a $3 million cumulative adjustment to Partners’ Equity and a corresponding adjustment to 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 primarily upon the historical loss-rate method established for various pools of accounts receivables with similar levels of credit risk. The historical loss-rates are then adjusted, as necessary, based on current conditions and forecasted information that could result in future uncollectable amounts. On an ongoing basis, we evaluate our customers’ financial strength and liquidity 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 and other receivable balances within other assets 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. The following table summarizes the required allowance for doubtful accounts.



	March 31, 2020		January 1, 2020

	(In millions)
Accounts receivable	$	2	$	2
Other assets	3		3
Total Allowance for doubtful accounts	$	5	$	5

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 write-downs to net realizable value related to natural gas and natural gas liquids inventory of $6 million and $1 million during the three months ended March 31, 2020 and 2019, respectively.

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(2) New Accounting Pronouncements

Accounting Standards to be Adopted in Future Periods

Reference Rate Reform

In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” This standard provides optional guidance, for a limited time, to ease the potential burden in accounting for or recognizing the effects of reference rate reform on financial reporting. The standard was effective upon issuance and generally can be applied through December 31, 2022. The Partnership is currently evaluating the impact this ASU will have on our Condensed Consolidated Financial Statements and related disclosures.

(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 months ended March 31, 2020 and 2019.



	Three Months Ended March 31, 2020
	Gathering and Processing		Transportation and Storage		Eliminations			Total

	(In millions)
Revenues:
Product sales:
Natural gas	$	56	$	73	$	(60	)	$	69
Natural gas liquids	172		2		(2		)	172
Condensate	27		—		—			27
Total revenues from natural gas, natural gas liquids, and condensate	255		75		(62		)	268
Gain on derivative activity	20		—		—			20
Total Product sales	$	275	$	75	$	(62	)	$	288
Service revenues:
Demand revenues	$	39	$	142	$	—		$	181
Volume-dependent revenues	163		17		(1		)	179
Total Service revenues	$	202	$	159	$	(1	)	$	360
Total Revenues	$	477	$	234	$	(63	)	$	648

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	Three Months Ended March 31, 2019
	Gathering and Processing			Transportation and Storage			Eliminations			Total

	(In millions)
Revenues:
Product sales:
Natural gas	$	128		$	162		$	(141	)	$	149
Natural gas liquids	270			6			(6		)	270
Condensate	34			—			—			34
Total revenues from natural gas, natural gas liquids, and condensate	432			168			(147		)	453
Loss on derivative activity	(9		)	(1		)	—			(10		)
Total Product sales	$	423		$	167		$	(147	)	$	443
Service revenues:
Demand revenues	$	60		$	131		$	—		$	191
Volume-dependent revenues	147			18			(4		)	161
Total Service revenues	$	207		$	149		$	(4	)	$	352
Total Revenues	$	630		$	316		$	(151	)	$	795

MRT Rate Case Settlements

In June 2018, MRT filed a general NGA rate case (the “2018 Rate Case”), and in October 2019, MRT filed a second rate case (the “2019 Rate Case”). MRT began collecting the rates proposed in the 2018 Rate Case, subject to refund, on January 1, 2019. On March 26, 2020, FERC issued an order approving settlements filed in the 2018 Rate Case and the 2019 Rate Case. Upon issuance of the order and approval of the settlement of the MRT rate cases, the Partnership recognized $17 million of revenues from amounts previously held in reserve related to transportation and storage services performed in 2019. As of March 31, 2020, $21 million is held in reserve to be refunded to customers, which is inclusive of interest and is expected to be paid in May 2020.

Accounts Receivable

The following table summarizes the components of accounts receivable, net of allowance for doubtful accounts.



	March 31, 2020		December 31, 2019

	(In millions)
Accounts Receivable:
Customers	$	176	$	239
Contract assets ⁽¹⁾	26		18
Non-customers	7		12
Total Accounts Receivable ⁽²⁾	$	209	$	269

____________________

(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 $7 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.

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The table below summarizes the change in the contract liabilities.



	March 31, 2020		December 31, 2019		Amounts recognized in revenues

	(In millions)
Deferred revenues ⁽¹⁾	$	47	$	48	$	19

The table below summarizes the timing of recognition of these contract liabilities as of March 31, 2020.



	2020		2021		2022		2023		2024 and After
	(In millions)
Deferred revenues ⁽¹⁾	$	22	$	6	$	6	$	6	$	7

____________________


(1)	Deferred revenues includes deferred revenue—affiliated companies. This amount is included in Other current liabilities and Other long-term liabilities.

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 March 31, 2020.



	2020		2021		2022		2023		2024 and After
	(In millions)
Transportation and Storage	$	343	$	308	$	240	$	225	$	702
Gathering and Processing	90		121		123		121		313
Total remaining performance obligations	$	433	$	429	$	363	$	346	$	1,015

(4) Leases

As of March 31, 2020, we have right-of-use assets of $31 million recorded as Other Assets, $7 million of corresponding obligations recorded as Other Current Liabilities and $27 million of corresponding obligations recorded as Other Liabilities on the Partnership’s Condensed Consolidated Balance Sheet. All lease obligations outstanding during the three months ended March 31, 2020 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 $5 million and $1 million during the three months ended March 31, 2020, respectively, and $7 million and $2 million during the three months ended March 31, 2019, respectively. As of March 31, 2020, the weighted average remaining lease term is 6.7 years and the weighted average discount rate is 5.43%.

The following table presents the Partnership’s lease cost.



	Three Months Ended March 31, 2020
	Gathering and Processing		Transportation and Storage		Total

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

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	Three Months Ended March 31, 2019
	Gathering and Processing		Transportation and Storage		Total

	(In millions)
Lease Cost:
Operating lease cost	$	2	$	—	$	2
Short-term lease cost	6		1		7
Total Lease Cost	$	8	$	1	$	9

Under ASC 842, as of March 31, 2020, the Partnership has operating lease obligations expiring at various dates. The $4 million difference between undiscounted cash flows for operating leases and our $34 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,
	2020		2021		2022		2023		2024		2025 and After		Total

	(In millions)
Noncancellable operating leases	$	7	$	6	$	5	$	5	$	4	$	11	$	38

(5) Earnings Per Limited Partner Unit

The following table illustrates the Partnership’s calculation of earnings per unit for common units. The dilutive effect of the unit-based awards discussed in Note 15 was less than $0.01 per unit during the three months ended March 31, 2020 and 2019.



	Three Months Ended March 31,
	2020			2019

	(In millions, except per unit data)
Net income	$	105		$	123
Net (loss) income attributable to noncontrolling interest	(7		)	1
Series A Preferred Unit distributions	9			9
General partner interest in net income	—			—
Net income available to common unitholders	$	103		$	113

Net income allocable to common units	$	103		$	113
Dilutive effect of Series A Preferred Unit distributions	9			—
Diluted net income allocable to common units	$	112		$	113

Basic earnings per unit
Common units	$	0.24		$	0.26

Basic weighted average number of common units outstanding ⁽¹⁾	437			435
Dilutive effect of Series A Preferred Units	144			—
Diluted weighted average number of common units outstanding	581			435

Diluted earnings per unit
Common units	$	0.19		$	0.26

____________________


(1)	Basic weighted average number of outstanding common units includes approximately two million and one million time-based phantom units for the three months ended March 31, 2020 and 2019, respectively.

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(6) 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.

The Partnership paid or has authorized payment of the following cash distributions to common unitholders, as applicable, during 2020 and 2019 (in millions, except for per unit amounts):

Three Months Ended

Record Date

Payment Date

Per Unit Distribution

Total Cash Distribution

March 31, 2020 ⁽¹⁾

May 19, 2020

May 27, 2020

0.16525

December 31, 2019

February 18, 2020

February 25, 2020

0.3305

144

September 30, 2019

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

_____________________


(1)	The Board of Directors declared this $0.16525 per common unit cash distribution on May 5, 2020, to be paid on May 27, 2020 to common unitholders of record at the close of business on May 19, 2020.

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2019 and 2020 (in millions, except for per unit amounts):

Three Months Ended

Record Date

Payment Date

Per Unit Distribution

Total Cash Distribution

March 31, 2020 ⁽¹⁾

May 5, 2020

May 15, 2020

0.625

December 31, 2019

February 7, 2020

February 14, 2020

0.625

September 30, 2019

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

_____________________


(1)	The Board of Directors declared a $0.625 per Series A Preferred Unit cash distribution on May 5, 2020, to be paid on May 15, 2020, to Series A Preferred unitholders of record at the close of business on May 5, 2020.

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 months ended March 31, 2020 and 2019, the Partnership did not issue common units under the ATM Program. As of March 31, 2020, $197 million of common units remained available for issuance through the ATM Program.

(7) Impairments of Long-lived Assets and Goodwill

Impairment of Long-lived Assets

The Partnership periodically evaluates long-lived assets, including property, plant and equipment when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. Due to decreases in natural gas and NGL market prices during 2020 as a result of the ongoing spread and economic effects of the COVID-19 pandemic, together with the recent dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia, as of March 31, 2020, management reassessed the carrying value of the Atoka assets, in which the Partnership owns a 50% interest in the consolidated joint venture, which is a component of the gathering and processing segment. Based on forecasted future undiscounted cash flows, management determined that the carrying value of the Atoka assets were not

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fully recoverable. The Partnership utilized the income approach (generally accepted valuation approach) to estimate the fair value of these assets. The primary inputs are forecasted cash flows and the discount rate. The fair value measurement is based on inputs that are not observable in the market and thus represent Level 3 inputs. Applying a discounted cash flow model to the property, plant and equipment, the Partnership recognized a $16 million impairment, which is included in Impairments on the Condensed Consolidated Statements of Income during the three months ended March 31, 2020.

Impairment of Goodwill

In the fourth quarter of 2017, as a result of the acquisition of ETGP, the Partnership recorded $12 million of goodwill associated with the Ark-La-Tex Basin reporting unit, included in the gathering and processing reportable segment.

The Partnership tests its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. During 2020, the energy industry was impacted by current and forward commodity price declines due to the ongoing spread and economic effects of the COVID-19 pandemic, together with the recent dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia. Amid such crude oil, NGL and natural gas price declines, producers have been cutting back spending and shifting their focus from emphasizing reserves growth, to increasing net cash flows and reducing outstanding debt, which consequently resulted in a decrease in rig count and in forecasted producer activity in the Ark-La-Tex Basin reporting unit during the first quarter of 2020. At the same time, unit prices and market multiples for midstream companies with gathering and processing operations have dropped to their lowest levels in the last three years. Due to the continuing decrease in forward commodity prices, the reduction in forecasted producer activities, the resulting decrease in our forecasted cash flows and the increase in the weighted average cost of capital, the Partnership determined that the fair value of the goodwill associated with our Ark-La-Tex Basin reporting unit would more likely than not be impaired. As a result, the Partnership performed a quantitative test for our goodwill and determined that the carrying value of the Ark-La-Tex Basin reporting unit exceeded its fair value and that goodwill associated with the Ark-La-Tex Basin was completely impaired in the amount of $12 million. The impairment is included in Impairments on the Condensed Consolidated Statements of Income for the three months ended March 31, 2020.

The following table presents the change in carrying amount of goodwill in each of our reportable segments.



	Gathering and Processing			Transportation and Storage		Total

	(In millions)
Balance as of December 31, 2019	$	12		$	—	$	12
Goodwill impairment	(12		)	—		(12		)
Balance as of March 31, 2020	$	—		$	—	$	—

(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 $6 million and $3 million during the three months ended March 31, 2020 and 2019, respectively, associated with these service agreements.

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The Partnership includes equity in earnings of equity method affiliate under the Other Income (Expense) caption in the Condensed Consolidated Statements of Income. The following table presents the amount of Equity in earnings of equity method affiliate recognized and Distributions from equity method affiliate received.



	Three Months Ended March 31,
	2020		2019

	(In millions)
Equity in Earnings of Equity Method Affiliate	$	6	$	3
Distributions from Equity Method Affiliate ⁽¹⁾	$	10	$	12

___________________


(1)	Distributions from equity method affiliate includes a $6 million and $3 million return on investment and a $4 million and $9 million return of investment for the three months ended March 31, 2020 and 2019, respectively.

The following table includes the summarized financial information of SESH.



	Three Months Ended March 31,
	2020		2019

	(In millions)
Income Statements:
Revenues	$	27	$	27
Operating income	$	16	$	11
Net income	$	11	$	7

(9) Debt

The following table presents the Partnership’s outstanding debt.



	March 31, 2020							December 31, 2019
	Outstanding Principal		Discount ⁽¹⁾			Total Debt		Outstanding Principal		Premium (Discount) ⁽¹⁾			Total Debt

	(In millions)
Commercial Paper	$	110	$	—		$	110	$	155	$	—		$	155
Revolving Credit Facility	300		—			300		—		—			—
2019 Term Loan Agreement	800		—			800		800		—			800
2024 Notes	600		—			600		600		—			600
2027 Notes	700		(2		)	698		700		(2		)	698
2028 Notes	800		(5		)	795		800		(5		)	795
2029 Notes	550		(1		)	549		550		(1		)	549
2044 Notes	550		—			550		550		—			550
EOIT Senior Notes	—		—			—		250		1			251
Total debt	$	4,410	$	(8	)	$	4,402	$	4,405	$	(7	)	$	4,398
Less: Short-term debt ⁽²⁾						110							155
Less: Current portion of long-term debt ⁽³⁾						—							251
Less: Unamortized debt expense⁽⁴⁾						22							23
Total long-term debt						$	4,270						$	3,969

____________________


(1)	Unamortized premium (discount) on long-term debt is amortized over the life of the respective debt.


(2)	Short-term debt includes $110 million and $155 million of outstanding commercial paper as of March 31, 2020 and December 31, 2019, respectively.


(3)	As of December 31, 2019, Current portion of long-term debt included $251 million outstanding balance of the EOIT Senior Notes which were repaid in March 2020.


(4)	As of March 31, 2020 and December 31, 2019, there was an additional $4 million of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above.

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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 $110 million and $155 million outstanding under our commercial paper program at March 31, 2020 and December 31, 2019, respectively. The weighted average interest rate for the outstanding commercial paper was 2.29% as of March 31, 2020.

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, five-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 March 31, 2020, there were $300 million 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 March 31, 2020, 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 March 31, 2020, the commitment fee under the restated Revolving Credit Facility was 0.20% per annum based on the Partnership’s credit ratings. The commitment fee is recorded as interest expense in the Partnership’s 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. As of March 31, 2020, there was $800 million outstanding under the 2019 Term Loan Agreement. 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 March 31, 2020, 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 March 31, 2020, the weighted average interest rate of the 2019 Term Loan Agreement was 3.00%.

Senior Notes

As of March 31, 2020, the Partnership’s debt included the 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes and 2044 Notes, which had $8 million of unamortized discount and $22 million of unamortized debt expense at March 31, 2020, resulting in effective interest rates of 4.01%, 4.57%, 5.20%, 4.31% and 5.08%, respectively, during the three months ended March 31, 2020. In March 2020, the Partnership’s EOIT Senior Notes matured and were paid using proceeds from the Revolving Credit Facility.

As of March 31, 2020, the Partnership was in compliance with all of its debt agreements, including financial covenants.

(10) Derivative Instruments and Hedging Activities

The primary risks managed using derivative instruments are commodity price and interest rate risks.

Derivatives Not Designated as Hedging Instruments

Derivative instruments not designated as hedging instruments for accounting purposes are utilized to manage the Partnership’s 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 following table presents the Partnership’s derivative instruments that were not designated as hedging instruments for accounting purposes.



	March 31, 2020		December 31, 2019
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas—TBtu ⁽¹⁾
Financial fixed futures/swaps	7	20	10	19
Financial basis futures/swaps	7	30	11	30
Financial swaptions ⁽²⁾	—	7	—	2
Physical purchases/sales	—	4	—	6
Crude oil (for condensate)—MBbl ⁽³⁾
Financial futures/swaps	—	630	—	990
Financial swaptions ⁽²⁾	—	165	—	225
Natural gas liquids—MBbl ⁽⁴⁾
Financial futures/swaps	2,205	2,085	2,490	2,415
Financial options	—	90	—	—

____________________


(1)	As of March 31, 2020, 87.9% of the natural gas contracts had durations of one year or less and 12.1% had durations of more than one year and less than two years. As of December 31, 2019, 86.6% of the natural gas contracts had durations of one year or less and 13.4% had durations of more than one year and less than two years.


(2)	The notional volume 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 volume hedged under the fixed price swap until the option expiration date. The notional volume represents the volume prior to option exercise.


(3)	As of March 31, 2020, 77.4% of the crude oil (for condensate) contracts had durations of one year or less and 22.6% had durations of more than one year and less than two years. As of December 31, 2019, 72.8% of the crude oil (for condensate) contracts had durations of one year or less and 27.2% had durations of more than one year and less than two years.


(4)	As of March 31, 2020, 82.5% of the natural gas liquids contracts had durations of one year or less and 17.5% had durations of more than one year and less than two years. As of December 31, 2019, 72.2% of the natural gas liquid contracts had durations of one year or less and 27.8% 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 following table presents the Partnership’s derivative instruments that were designated as hedging instruments for accounting purposes.



	March 31, 2020		December 31, 2019
	Gross Notional Value
	(In millions)
Interest rate swaps	$	300	$	300

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Balance Sheet Presentation Related to Derivative Instruments

The following table presents the fair value of the derivative instruments that are included in the Partnership’s Condensed Consolidated Balance Sheets that were not designated as hedging instruments for accounting purposes.



		March 31, 2020				December 31, 2019
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities

		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	7	$	6	$	7	$	5
Financial swaptions	Other Current	2		1		—		—
Financial futures/swaps	Other	—		—		—		1
Physical purchases/sales	Other Current	4		—		5		—
Crude oil (for condensate)
Financial futures/swaps	Other Current	6		8		1		19
Financial swaptions	Other Current	4		—		—		—
Financial futures/swaps	Other	1		5		—		8
Natural gas liquids
Financial futures/swaps	Other Current	16		5		25		3
Financial swaptions	Other Current	1		—		—		—
Financial futures/swaps	Other	6		1		11		2
Total gross commodity derivatives ⁽¹⁾		$	47	$	26	$	49	$	38

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(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 March 31, 2020 and December 31, 2019.

The following table presents the fair value of the derivative instruments that are included in the Partnership’s Condensed Consolidated Balance Sheets that were designated as hedging instruments for accounting purposes.



		March 31, 2020				December 31, 2019
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities

		(In millions)
Interest rate swaps	Other Current	$	—	$	5	$	—	$	1
Interest rate swaps	Other	—		4		—		2
Total gross interest rate derivatives ⁽¹⁾		$	—	$	9	$	—	$	3

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(1)	All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of March 31, 2020 and December 31, 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.



	Amounts Recognized in Income
	Three Months Ended March 31,
	2020			2019

	(In millions)
Natural gas
Financial futures/swaps gains (losses)	$	4		$	(1	)
Financial swaptions (losses)	(1		)	—
Physical purchases/sales gains (losses)	1			(1		)
Crude oil (for condensate)
Financial futures/swaps gains (losses)	19			(11		)
Financial swaptions gains	4			—
Natural gas liquids
Financial futures/swaps (losses) gains	(7		)	3
Total	$	20		$	(10	)

For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended March 31, 2020 and 2019, 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.



	Three Months Ended March 31,
	2020		2019

	(In millions)
Change in fair value of commodity derivatives	$	10	$	(12	)
Realized gain on commodity derivatives	10		2
Gain (loss) on commodity derivative activity	$	20	$	(10	)

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 March 31, 2020, under these obligations, the Partnership has posted no cash collateral related to natural gas swaps and swaptions, crude oil 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. 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 months ended March 31, 2020, there were no transfers between levels. As of March 31, 2020, there were no contracts classified as Level 3.

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.



	March 31, 2020				December 31, 2019
	Carrying Amount		Fair Value		Carrying Amount		Fair Value

	(In millions)
Debt
Revolving Credit Facility (Level 2) ⁽¹⁾	$	300	$	300	$	—	$	—
2019 Term Loan Agreement (Level 2)	800		800		800		800
2024 Notes (Level 2)	600		333		600		614
2027 Notes (Level 2)	698		340		698		698
2028 Notes (Level 2)	795		398		795		811
2029 Notes (Level 2)	549		253		549		526
2044 Notes (Level 2)	550		236		550		506
EOIT Senior Notes (Level 2)	—		—		251		252

____________________


(1)	Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $110 million and $155 million of commercial paper was outstanding as of March 31, 2020 and December 31, 2019, respectively.

The fair value of the Partnership’s Revolving Credit Facility, 2019 Term Loan Agreement, 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 March 31, 2020, no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities, other than those discussed in Note 7.

Based upon review of forecasted undiscounted cash flows as of March 31, 2020, all of the asset groups were considered recoverable, other than those discussed in Note 7. Future price declines, throughput declines, contracted capacity declines, cost increases, regulatory or political environment changes and other changes in market conditions, including the ongoing spread and economic effects of COVID-19 and the recent dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia, could reduce forecasted undiscounted cash flows.

Contracts with Master Netting Arrangements

As of March 31, 2020, 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.



March 31, 2020	Commodity Contracts						Gas Imbalances ⁽¹⁾
	Assets			Liabilities			Assets ⁽²⁾		Liabilities ⁽³⁾

	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	5		$	18		$	—	$	—
Significant other observable inputs (Level 2)	42			8			13		10
Total fair value	47			26			13		10
Netting adjustments	(26		)	(26		)	—		—
Total	$	21		$	—		$	13	$	10



December 31, 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)	$	5		$	31		$	—	$	—
Significant other observable inputs (Level 2)	44			7			14		11
Total fair value	49			38			14		11
Netting adjustments	(37		)	(37		)	—		—
Total	$	12		$	1		$	14	$	11

______________________


(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 March 31, 2020 and December 31, 2019.


(2)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $23 million and $21 million at March 31, 2020 and December 31, 2019, 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 $7 million and $8 million at March 31, 2020 and December 31, 2019, 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:



	Three Months Ended March 31,
	2020			2019

	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	43		$	32
Non-cash transactions:
Accounts payable related to capital expenditures	8			39
Lease liabilities related to (derecognition) recognition of right-of-use assets	(4		)	35
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)	(3		)	—

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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:



	March 31,
	2020		2019

	(In millions)
Cash and cash equivalents	$	4	$	18
Restricted cash	—		1
Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	4	$	19

(13) Related Party Transactions

MRT provides firm transportation and firm storage services to CenterPoint Energy’s LDCs in Arkansas and Louisiana. As part of the MRT rate case settlements, contracts for these services were extended and are in effect through July 31, 2028 and will remain in effect thereafter unless and until terminated by either party upon twelve months’ prior written notice.

The Partnership’s revenues from affiliated companies accounted for 8% and 6% of total revenues during the three months ended March 31, 2020 and 2019, respectively. The following table presents the amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income.



	Three Months Ended March 31,
	2020		2019

	(In millions)
Gas transportation and storage service revenues — CenterPoint Energy	$	37	$	33
Natural gas product sales — CenterPoint Energy	—		1
Gas transportation and storage service revenues — OGE Energy	9		13
Natural gas product sales — OGE Energy	5		1
Total revenues — affiliated companies	$	51	$	48

The following table presents the amounts of natural gas purchased from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income.



	Three Months Ended March 31,
	2020		2019

	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	1	$	—
Cost of natural gas purchases — OGE Energy	8		6
Total cost of natural gas purchases — affiliated companies	$	9	$	6

Corporate services and seconded employees

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 2020 are $0 million and $1 million, respectively.

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As of March 31, 2020, 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 an annual cap of $5 million until secondment is terminated.

The following table presents the amounts charged to the Partnership by affiliates for seconded employees, included primarily in Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income.



	Three Months Ended March 31,
	2020		2019

	(In millions)
Seconded Employee Costs — OGE Energy	$	3	$	6

(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 March 31, 2020, the Partnership estimates the remaining associated minimum volume commitment fee to be $187 million. Minimum volume commitment fees are expected to be $15 million for the remainder of 2020, $23 million per year from 2021 through 2027 and $11 million in 2028.

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 requested approval to transfer existing EGT transportation infrastructure to the Gulf Run Pipeline. The Company filed applications with FERC to obtain authorization to construct and operate the pipeline on February 28, 2020. Under the precedent agreement, the Partnership estimates the cost to complete the Gulf Run Pipeline project to fulfill its obligations under the precedent agreement would be as much as $500 million. The project is backed by a 20-year firm transportation service agreement. 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. On January 27, 2020, FERC approved the sale. The Partnership closed the sale on April 1, 2020.

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(15) Equity-Based Compensation

The following table summarizes the Partnership’s equity-based compensation expense related to performance units and phantom units for the Partnership’s employees and independent directors.



	Three Months Ended March 31,
	2020		2019

	(In millions)
Performance units	$	2	$	3
Phantom units	2		1
Total compensation expense	$	4	$	4

The following table presents the assumptions related to the performance share units granted in 2020.



	2020
Number of units granted	933,738
Fair value of units granted	$	7.00
Expected distribution yield	12.27		%
Expected price volatility	27.70		%
Risk-free interest rate	0.85		%
Expected life of units (in years)	3

The following table presents the number of phantom units granted and the grant date fair value related to the phantom units granted in 2020.



	2020
Phantom Units granted	941,732
Fair value of phantom units granted	$6.48 - $10.13

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Units Outstanding

A summary of the activity for the Partnership’s performance units and phantom units applicable to the Partnership’s employees at March 31, 2020 and changes during 2020 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, 2019	1,393,329			$	19.04	1,392,560			$	14.65
Granted ⁽¹⁾	933,738			7.00		941,732			8.41
Vested ⁽²⁾	(381,981		)	19.25		(347,287		)	16.10
Forfeited	(11,621		)	19.12		(10,611		)	14.81
Units outstanding at March 31, 2020	1,933,465			$	13.18	1,976,394			$	10.55
Aggregate intrinsic value of units outstanding at March 31, 2020	$	5				$	5

_____________________


(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 March 31, 2020 include 376,292 units from the 2017 annual grant, which were approved by the Board of Directors in 2017 and, based on the level of achievement of a performance goal established by the Board of Directors over the performance period of January 1, 2017 through December 31, 2019, no performance units vested.

Unrecognized Compensation Cost

The following table summarizes 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.



	March 31, 2020
	Unrecognized Compensation Cost (In millions)		Weighted Average Period for Recognition (In years)
Performance Units	$	16	2.18
Phantom Units	13		1.97
Total	$	29

As of March 31, 2020, there were 4,987,106 units available for issuance under the long-term incentive plan.

(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 2019 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.

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Financial data for reportable segments are as follows:



Three Months Ended March 31, 2020	Gathering and Processing		Transportation ⁽¹⁾ and Storage		Eliminations			Total

	(In millions)
Product sales	$	275	$	75	$	(62	)	$	288
Service revenues	202		159		(1		)	360
Total Revenues	477		234		(63		)	648
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	211		78		(63		)	226
Operation and maintenance, General and administrative	81		45		—			126
Depreciation and amortization	74		30		—			104
Impairments	28		—		—			28
Taxes other than income tax	11		7		—			18
Operating income	$	72	$	74	$	—		$	146
Total Assets	$	9,659	$	5,702	$	(3,244	)	$	12,117
Capital expenditures	$	34	$	20	$	—		$	54


Three Months Ended March 31, 2019	Gathering and Processing		Transportation ⁽¹⁾ and Storage		Eliminations			Total

	(In millions)
Product sales	$	423	$	167	$	(147	)	$	443
Service revenues	207		149		(4		)	352
Total Revenues	630		316		(151		)	795
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	360		169		(151		)	378
Operation and maintenance, General and administrative	84		45		—			129
Depreciation and amortization	74		31		—			105
Taxes other than income tax	11		7		—			18
Operating income	$	101	$	64	$	—		$	165
Total assets as of December 31, 2019	$	9,739	$	5,886	$	(3,359	)	$	12,266
Capital expenditures	$	107	$	36	$	—		$	143

_____________________


(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 months ended March 31, 2020 and 2019.

(17) Subsequent Event

On April 8, 2020, we experienced pipeline damage to one of our rich gas gathering systems in the Ark-La-Tex Basin of our gathering and processing segment. We have ceased operation of this system and are in process of abandoning it in-place. We expect to recognize a loss on retirement of approximately $20 million during the second quarter of 2020. Other than recognition of the non-cash loss on retirement, we do not anticipate a material impact to our financial position, results of operations or cash flows related to the abandonment of this system.

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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, 2019, 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, including risks resulting from the ongoing spread and economic effects of COVID-19. Our actual results could differ materially from those discussed in these forward-looking statements. Please read “Forward-Looking Statements.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

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, including the impacts of the COVID-19 pandemic. 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

Coronavirus Pandemic

In March 2020, the World Health Organization categorized the recent outbreak of COVID-19 as a pandemic. The COVID-19 pandemic has led to significant economic disruption globally, including in the areas of the United States in which we operate. Governmental authorities have taken action to limit the spread of COVID-19 through social distancing guidelines, travel restrictions, and stay-at-home orders, which have caused many businesses to adjust, reduce or suspend activities. Concerns about global economic growth, as well as uncertainty regarding the timing, pace and extent of an economic recovery in the United States and abroad, have had a significant adverse impact on commodity prices and financial markets.

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Our gathering and processing and our transportation and storage assets have continued to operate as critical infrastructure necessary to support the supply of natural gas, NGLs and crude oil. We have taken action to protect the health and safety of our workers, while continuing to operate, and to maintain the safety and integrity of, our assets. Where possible, our employees have worked remotely to support our business. Where continuous remote work is not possible, we have enlisted strategies to reduce the likelihood of spreading the disease. These strategies include social distancing, discontinuing nonessential travel, routinely disinfecting and cleaning workspaces, promoting frequent and thorough handwashing, encouraging employees to stay home if they are sick, urging employees to wear cloth face coverings, and educating employees to self-monitor for signs and symptoms of COVID-19.

Prior to the COVID-19 pandemic, the price of natural gas, NGLs and crude oil began to decline due to oversupply. The price of, and global demand for, these commodities have declined significantly as a result of the ongoing spread and economic effects of the COVID-19 pandemic and the significant governmental measures being implemented to control the spread of the virus. In addition, the recent dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia have exacerbated the decline in the price of NGLs and crude oil. Despite the subsequent agreement in April 2020 by a coalition of nations including Russia and Saudi Arabia to reduce production of crude oil, the price of NGLs and crude oil have remained depressed.

Financial markets have experienced sharp declines and extreme volatility as a result of the economic uncertainty arising out of the COVID-19 pandemic. The financial market declines and volatility, together with deteriorating credit, liquidity concerns, decreasing production, and increasing inventories, are conditions that are associated with a general economic downturn. Producers have announced and begun to implement plans to reduce production and decrease the drilling and completion of wells in response to these conditions. The plans include reductions in the exploration, development and production activity of producers across our areas of operation. As a result, the effects of the COVID-19 pandemic have begun, and may continue to negatively impact the demand for midstream services. The effects of the COVID-19 pandemic may also increase counterparty credit risk. Some customers may encounter severe financial problems that could limit our ability to collect amounts owed to us or to enforce performance of other obligations under contractual arrangements. During the first quarter of 2020 as compared to the first quarter of 2019, our gathered volumes and gross margin increased, and our processed volumes, transported volumes, and revenue decreased. Because of the uncertainty in the production of natural gas, NGLs and crude oil and in the demand for midstream services, as well as uncertainty regarding the financial impact of the current economic situation on the creditworthiness of our customers, these results may not be indicative of our future results. For more information on our results, see “Results of Operations” below.

We are actively responding to the impacts of these developments on our business. On April 1, 2020, we announced distribution, capital and cost reductions intended to fortify our financial position, protect our balance sheet and ensure our liquidity. These measures include:


•	A 50% reduction in our quarterly distribution per common unit from $0.3305 to $0.16525 to retain cash in order to provide funding for our capital investment program;


•	A $115 million reduction from the high end of the range of our previously forecasted expansion capital expenditures for 2020, which limits our forecasted expansion capital expenditures primarily to projects that serve incremental firm transportation commitments and support expected levels of contracted producer activity;


•	A $35 million decrease in forecasted operations and maintenance and general and administrative expenses for 2020, that we anticipate will grow to a $70 million run-rate savings in 2021; and


•	A reduction in maintenance capital of $20 million, or 17%, from the midpoint of our previously provided outlook for 2020, that we anticipate continuing in 2021.

We believe that these measures will allow us to fully fund our business and reduce our total debt in 2020.

We cannot currently predict the duration and extent of the impact of the COVID-19 pandemic on the financial markets, the commodity markets, the production of natural gas, NGLs and crude oil or the demand for midstream services. During the first quarter of 2020, the Partnership recognized impairments of long-lived assets and goodwill of $28 million. Due to decreases in natural gas and NGL market prices during 2020 as a result of the ongoing spread and economic effects of the COVID-19 pandemic, together with the recent dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia, the Partnership recognized a $16 million impairment of the carrying value of the Atoka assets, a component of the gathering and processing segment in which the Partnership owns a 50% interest in the consolidated joint venture. Additionally, due to the continuing decreases in forward commodity prices, the announced reductions in producer activities, the resulting anticipated decrease in our cash flows and the increase in the weighted average cost of capital, the Partnership determined that the fair value of the goodwill associated with our Ark-La-Tex Basin reporting unit was completely impaired and recognized $12 million of impairment. We currently have no goodwill recorded on our books for any of our reporting units for either our gathering and

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processing or transportation and storage segments. Depending upon the duration and extent of reduced producer activities, energy commodity prices, and economic activity from the COVID-19 pandemic and attendant reduction in demand for hydrocarbons, we may experience asset impairments in future reporting periods.

Commercial Update

Sale of Interest in Bistineau Storage Facility

Regulatory Update

MRT Rate Case

In June 2018, MRT filed a general NGA rate case (the “2018 Rate Case”), and in October 2019, MRT filed a second rate case (the “2019 Rate Case”). MRT began collecting the rates proposed in the 2018 Rate Case, subject to refund, on January 1, 2019. On November 5, 2019, as supplemented on December 13, 2019, MRT filed an uncontested proposed settlement for the 2018 Rate Case. On November 5, 2019, as supplemented on December 12, 2019, MRT filed an uncontested proposed settlement for the 2019 Rate Case.

On March 26, 2020, FERC issued an order approving settlements filed in the 2018 Rate Case and the 2019 Rate Case. The settlements also include contract extensions for most firm transportation and storage customers through July 31, 2024. Upon issuance of the order and approval of the settlements of the MRT rate cases, the Partnership recognized $17 million of revenues from amounts previously held in reserve related to transportation and storage services performed in 2019. As of March 31, 2020, $21 million is held in reserve to be refunded to customers, which is inclusive of interest and is expected to be paid in May 2020.

PHMSA Update

We continue to assess the impact that the Safety of Hazardous Liquid Pipelines rule and the Safety of Gas Transmission Pipelines rule, both of which will become effective July 1, 2020, will have on our costs of operations and revenue from operations. In connection with our compliance with the Safety of Hazardous Liquid Pipelines rule and Safety of Gas Transmission Pipelines rule, we currently estimate that we will not incur material costs in 2020, and we estimate that we could incur an average of $10 million per year beginning in 2021.

The Pipeline Safety: Safety of Gas Transmission Pipelines, Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments Rule and the Safety of Gas Gathering Pipelines rule, are expected to be published and effective in 2021. While we cannot predict the outcome of pending or future legislative or regulatory initiatives, we anticipate that pipeline safety requirements will continue to become more stringent over time. As a result, we may incur significant additional costs to comply with the new pipeline safety regulations, the pending pipeline safety regulations, and any new pipeline safety laws and regulations associated with our pipeline facilities, which could have a material impact on our costs of operations and revenue from operations.

Environmental Update

In April 2020, the federal district court for the district of Montana issued a broad order vacating the U.S. Army Corps of Engineers Clean Water Act Section 404 Nationwide Permit 12 (“NWP 12”) for alleged failure to comply with consultation requirements under the federal Endangered Species Act. Pipeline companies and other developers of underground infrastructure frequently rely upon NWP 12 and other general permits for construction and maintenance projects in jurisdictional wetland areas. While the full extent and impact of the court’s action is unclear at this time, a disruption in our ability to obtain coverage under NWP 12 or other general permits may result in increased costs and project delays if we are required to seek individual permits from the U.S. Army Corps of Engineers.

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Liquidity Update

EOIT Senior Notes

On March 16, 2020, the Partnership’s EOIT Senior Notes matured and were paid using proceeds from the Revolving Credit Facility. 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.



Three Months Ended March 31, 2020	Gathering and Processing		Transportation and Storage		Eliminations			Enable Midstream Partners, LP

	(In millions)
Product sales	$	275	$	75	$	(62	)	$	288
Service revenues	202		159		(1		)	360
Total Revenues	477		234		(63		)	648
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	211		78		(63		)	226
Gross margin ⁽¹⁾	266		156		—			422
Operation and maintenance, General and administrative	81		45		—			126
Depreciation and amortization	74		30		—			104
Impairments	28		—		—			28
Taxes other than income tax	11		7		—			18
Operating income	$	72	$	74	$	—		$	146
Equity in earnings of equity method affiliate	$	—	$	6	$	—		$	6



Three Months Ended March 31, 2019	Gathering and Processing		Transportation and Storage		Eliminations			Enable Midstream Partners, LP

	(In millions)
Product sales	$	423	$	167	$	(147	)	$	443
Service revenues	207		149		(4		)	352
Total Revenues	630		316		(151		)	795
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	360		169		(151		)	378
Gross margin ⁽¹⁾	270		147		—			417
Operation and maintenance, General and administrative	84		45		—			129
Depreciation and amortization	74		31		—			105
Taxes other than income tax	11		7		—			18
Operating income	$	101	$	64	$	—		$	165
Equity in earnings of equity method affiliate	$	—	$	3	$	—		$	3

_____________________


(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 March 31,
	2020	2019

Operating Data:
Natural gas gathered volumes—TBtu	411	409
Natural gas gathered volumes—TBtu/d	4.52	4.54
Natural gas processed volumes—TBtu ⁽¹⁾	222	229
Natural gas processed volumes—TBtu/d ⁽¹⁾	2.44	2.54
NGLs produced—MBbl/d ⁽¹⁾⁽²⁾	120.86	138.19
NGLs sold—MBbl/d ⁽²⁾⁽³⁾	121.32	140.09
Condensate sold—MBbl/d	8.23	8.35
Crude oil and condensate gathered volumes—MBbl/d	141.25	107.90
Transported volumes—TBtu	597	601
Transported volumes—TBtu/d	6.56	6.67
Interstate firm contracted capacity—Bcf/d	6.48	6.52
Intrastate average deliveries—TBtu/d	2.07	2.32

_____________________


(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 March 31,
	2020	2019
Anadarko
Gathered volumes—TBtu/d	2.29	2.35
Natural gas processed volumes—TBtu/d ⁽¹⁾	2.08	2.12
NGLs produced—MBbl/d ⁽¹⁾⁽²⁾	106.58	120.43
Crude oil and condensate gathered volumes—MBbl/d	114.48	76.54
Arkoma
Gathered volumes—TBtu/d	0.44	0.49
Natural gas processed volumes—TBtu/d ⁽¹⁾	0.08	0.10
NGLs produced—MBbl/d ⁽¹⁾⁽²⁾	3.90	6.23
Ark-La-Tex
Gathered volumes—TBtu/d	1.79	1.70
Natural gas processed volumes—TBtu/d	0.28	0.32
NGLs produced—MBbl/d ⁽¹⁾⁽²⁾	10.38	11.53
Williston
Crude oil gathered volumes—MBbl/d	26.77	31.36

_____________________


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


(2)	Excludes condensate.

Gathering and Processing

Three months ended March 31, 2020 compared to three months ended March 31, 2019. Our gathering and processing segment reported operating income of $72 million for the three months ended March 31, 2020 compared to operating income of $101 million for the three months ended March 31, 2019. The difference of $29 million in operating income between periods was primarily due to $28 million of goodwill and long-lived asset impairments recognized in 2020 and a $4 million decrease in gross margin, partially offset by a $3 million decrease in operation and maintenance and general and administrative expenses during the three months ended March 31, 2020.

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Our gathering and processing segment revenues decreased $153 million. The decrease was primarily due to the following:

Product Sales:


•	revenues from NGL sales decreased $105 million primarily due to a decrease in the average realized sales price from lower average market prices for all NGL products and lower processed volumes, partially offset by higher recoveries of all NGL products other than ethane in the Anadarko Basin and


•	revenues from natural gas sales decreased $72 million due to lower average natural gas sales prices and lower sales volumes.

These decreases were partially offset by:


•	changes in the fair value of natural gas, condensate and NGL derivatives increased $22 million and


•	realized gains on natural gas, condensate and NGL derivatives, which increased $7 million.

Service Revenues:


•	processing service revenues decreased $8 million due to lower processed volumes under fee-based arrangements, partially offset by higher consideration received from percent-of-proceeds, percent-of-liquids and keep-whole processing arrangements due to an increase in retained volumes at lower average market prices and


•	natural gas gathering revenues decreased $2 million due to lower gathered volumes in Anadarko and Arkoma Basins and lower shortfall payments associated with the expiration of certain minimum volume commitment contracts in the Ark-La-Tex and Arkoma Basins, partially offset by higher revenue associated with the amendment of certain minimum volume commitment contracts in the Arkoma Basin.

These decreases were partially offset by increased crude oil, condensate and produced water gathering revenues of $5 million primarily due to an increase in gathered volumes in the Anadarko Basin, partially offset by a decrease in gathered volumes in the Williston Basin.

Our gathering and processing segment gross margin decreased $4 million. The decrease was primarily due to the following:


•	revenues from NGL sales less the cost of NGLs decreased $17 million due to lower average sales prices for all NGL products, partially offset by higher recoveries of all NGL products other than ethane in the Anadarko Basin,


•	revenues from natural gas sales less the cost of natural gas decreased approximately $11 million due to lower average natural gas sales prices and lower sales volumes,


•	processing service fees decreased $8 million due to lower processed volumes under fee-based arrangements, partially offset by higher consideration received from percent-of-proceeds, percent-of-liquids and keep-whole processing arrangements due to an increase in retained volumes at lower average market prices, and


•	natural gas gathering fees decreased $2 million due to lower gathered volumes in Anadarko and Arkoma Basins and lower shortfall payments associated with the expiration of certain minimum volume commitment contracts in the Ark-La-Tex and Arkoma Basins, partially offset by higher revenue associated with the amendment of certain minimum volume commitment contracts in the Arkoma Basin.

These decreases were partially offset by:


•	changes in the fair value of natural gas, condensate and NGL derivatives increased $22 million,


•	realized gains on natural gas, condensate and NGL derivatives, which increased $7 million, and


•	crude oil, condensate and produced water gathering revenues increased $5 million primarily due to an increase in gathered volumes in the Anadarko Basin, partially offset by a decrease in gathered volumes in the Williston Basin.

Our gathering and processing segment operation and maintenance and general and administrative expenses decreased $3 million. The decrease was primarily due to a $2 million decrease in compressor rentals, a $2 million decrease in materials and supplies due to the timing of operation and maintenance activities and an increase in maintenance on treating plants in the prior year, and a $1 million decrease in contract services expenses. These decreases were partially offset by a $1 million increase in payroll-related costs and a $1 million increase due to lower capitalized overhead costs.

During the three months ended March 31, 2020, our gathering and processing segment recognized impairments of long-lived assets and goodwill of $28 million. Due to decreases of crude oil and natural gas prices during 2020, management reassessed the carrying value of the Partnership's investment in the Atoka assets, a component of the gathering and processing segment. Based on forecasted future undiscounted cash flows, the Partnership determined that the carrying value of the Atoka assets was not fully recoverable and recognized $16 million of impairment expense. Due to the continuing decreases in forward commodity prices, the reduction in forecasted producer activities, the resulting decrease in our forecasted cash flows and the increase in the weighted average cost of capital, the Partnership determined that the fair value of the goodwill associated with our Ark-La-Tex Basin reporting unit was completely impaired and recognized $12 million of impairment expense.

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Transportation and Storage

Three Months Ended March 31, 2020 compared to three months ended March 31, 2019. Our transportation and storage segment reported operating income of $74 million for the three months ended March 31, 2020 compared to operating income of $64 million for the three months ended March 31, 2019. The difference of $10 million in operating income between periods was primarily due to a $9 million increase in gross margin and a $1 million decrease in depreciation and amortization.

Our transportation and storage segment revenues decreased $82 million. The decrease was primarily due to the following:

Product Sales:


•	revenues from natural gas sales decreased $89 million primarily due to lower sales volumes and lower average sales prices, and


•	revenues from NGL sales decreased $4 million due to lower average sales prices and lower volumes.

These decreases were partially offset by realized gains on natural gas derivatives, which increased $1 million.

Service Revenues:


•	volume-dependent transportation and storage revenues decreased $1 million due to lower off-system intrastate transportation rates and volumes, partially offset by the recognition of $1 million of revenue upon the settlement of the MRT rate case.

This decrease was partially offset by firm transportation and storage services, which increased $11 million due to the recognition of $16 million of revenue upon the settlement of the MRT rate case, partially offset by lower interstate contracted capacity and lower rates on certain contracts for intrastate service with power generators.

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


•	firm transportation and storage services increased $11 million due to the recognition of $16 million of revenue upon the settlement of the MRT rate case, partially offset by lower interstate contracted capacity and lower rates on certain contracts for intrastate service with power generators,


•	system management activities increased $4 million, and


•	realized gains on natural gas derivatives, which increased $1 million.

These increases were partially offset by:


•	natural gas storage inventory decreased $5 million due to lower of cost or net realizable value adjustments,


•	volume-dependent transportation and storage revenues decreased $1 million due to lower off-system intrastate transportation rates and volumes, partially offset by the recognition of $1 million of revenue upon the settlement of the MRT rate case, and


•	revenues from NGL sales less the cost of NGLs decreased $1 million due to a decrease in average NGL prices and lower volumes.

Our transportation and storage segment operation and maintenance and general and administrative expenses remained flat. The activity included 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, offset by a $1 million decrease in professional services due to higher rate case costs in the prior year.

Our transportation and storage segment depreciation and amortization decreased $1 million primarily due to retirements of general plant assets.

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Condensed Consolidated Interim Information



	Three Months Ended March 31,
	2020			2019

	(In millions)
Operating Income	$	146		$	165
Other Income (Expense):
Interest expense	(47		)	(46		)
Equity in earnings of equity method affiliate	6			3
Total Other Expense	(41		)	(43		)
Income Before Income Taxes	105			122
Income tax benefit	—			(1		)
Net Income	$	105		$	123
Less: Net (loss) income attributable to noncontrolling interest	(7		)	1
Net Income Attributable to Limited Partners	$	112		$	122
Less: Series A Preferred Unit distributions	9			9
Net Income Attributable to Common Units	$	103		$	113

Three Months Ended March 31, 2020 compared to Three Months Ended March 31, 2019

Net Income Attributable to Limited Partners. We reported net income attributable to limited partners of $112 million in the three months ended March 31, 2020 compared to net income attributable to limited partners of $122 million in the three months ended March 31, 2019. The decrease in net income attributable to limited partners of $10 million was primarily attributable to an decrease in operating income of $19 million, an increase in interest expense of $1 million and an income tax benefit of $1 million in the prior year with no tax effect in the current year, partially offset by a $7 million loss attributable to noncontrolling interest due to an impairment in the Partnership’s Atoka assets of which the Partnership owns a 50% interest in the consolidated joint venture and an increase in equity in earnings of equity method affiliate of $3 million in the three months ended March 31, 2020.

Equity in Earnings of Equity Method Affiliate. Equity in earnings of equity method affiliate increased $3 million primarily due to a decrease of $2 million in operating expenses and a decrease in ad valorem taxes of $1 million due to a favorable assessment reducing the tax expense in the current year.

Interest Expense. Interest expense increased $1 million primarily due to an increase in principal amounts on the Partnership’s outstanding debt.

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.

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	Three Months Ended March 31,
	2020		2019

	(In millions)
Reconciliation of Gross margin to Total Revenues:
Consolidated
Product sales	$	288	$	443
Service revenues	360		352
Total Revenues	648		795
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)	226		378
Gross margin	$	422	$	417

Reportable Segments
Gathering and Processing
Product sales	$	275	$	423
Service revenues	202		207
Total Revenues	477		630
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)	211		360
Gross margin	$	266	$	270

Transportation and Storage
Product sales	$	75	$	167
Service revenues	159		149
Total Revenues	234		316
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)	78		169
Gross margin	$	156	$	147

The following table shows the components of our gross margin.



	Fee-Based ⁽¹⁾
Three Months Ended March 31, 2020	Demand		Volume- Dependent		Commodity- Based⁽¹⁾		Total
Gathering and Processing Segment	15	%	61	%	24	%	100	%
Transportation and Storage Segment	91	%	11	%	(2	)%	100	%
Partnership Weighted Average	43	%	42	%	15	%	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.

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	Three Months Ended March 31,
	2020			2019

	(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	$	112		$	122
Depreciation and amortization expense	104			105
Interest expense, net of interest income	47			46
Income tax benefit	—			(1		)
Distributions received from equity method affiliate in excess of equity earnings	4			9
Non-cash equity-based compensation	4			4
Change in fair value of derivatives ⁽¹⁾	(10		)	12
Other non-cash losses ⁽²⁾	5			1
Impairments	28			—
Noncontrolling Interest Share of Adjusted EBITDA	(8		)	(1		)
Adjusted EBITDA	$	286		$	297
Series A Preferred Unit distributions ⁽³⁾	(9		)	(9		)
Distributions for phantom and performance units ⁽⁴⁾	—			(9		)
Adjusted interest expense ⁽⁵⁾	(47		)	(47		)
Maintenance capital expenditures	(16		)	(24		)
DCF	$	214		$	208

Distributions related to common unitholders ⁽⁶⁾	$	72		$	138

Distribution coverage ratio ⁽⁷⁾	2.97			1.51

____________________


(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 includes write-downs and loss on sale of assets.


(3)	This amount represents the quarterly cash distributions on the Series A Preferred Units declared for the three months ended March 31, 2020 and 2019. 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 2020 reflect estimated cash distributions for common units outstanding for the quarter ended March 31, 2020.


(7)	Distribution coverage ratio is computed by dividing DCF by Distributions related to common unitholders.

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	Three Months Ended March 31,
	2020			2019

	(In millions)
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities	$	200		$	215
Interest expense, net of interest income	47			46
Noncontrolling Interest share of net income ⁽¹⁾	(1		)	(1		)
Current income taxes	—			(1		)
Other non-cash items ⁽²⁾	4			—
Changes in operating working capital which (provided) used cash:
Accounts receivable	(60		)	(29		)
Accounts payable	58			55
Other, including changes in noncurrent assets and liabilities	44			(9		)
Return of investment in equity method affiliate	4			9
Change in fair value of derivatives ⁽³⁾	(10		)	12
Adjusted EBITDA	$	286		$	297

____________________


(1)	Noncontrolling Interest share of net income is net of minority interest share of the non-cash impairment of the Atoka assets.


(2)	Other non-cash items includes write-downs of assets.


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



	Three Months Ended March 31,
	2020			2019

	(In millions)
Reconciliation of Adjusted interest expense to Interest expense:
Interest expense	$	47		$	46
Interest income	—			—
Amortization of premium on long-term debt	1			1
Capitalized interest on expansion capital	—			1
Amortization of debt expense and discount	(1		)	(1		)
Adjusted interest expense	$	47		$	47

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. Additionally, we may from time to time seek to retire or purchase our outstanding debt through cash purchases, in open market purchases, privately negotiated transactions, tender offers or otherwise. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. We expect that our liquidity and capital resource needs will be met by cash on hand, operating cash flow due to projected reductions in distribution, capital expenditures and operation and maintenance expense, proceeds from commercial paper issuances and borrowings under our Revolving Credit Facility. COVID-19 has led to a significant disruption in the equity and debt capital markets, which could hinder our ability to raise new capital or obtain financing on acceptable terms. See “Recent Developments” above for further discussion of the impact of COVID-19. 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.

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 March 31, 2020, we

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had a working capital deficit of $58 million. The deficit is primarily due to $110 million of commercial paper outstanding as of March 31, 2020. 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.



	Three Months Ended March 31,
	2020			2019

	(In millions)
Net cash provided by operating activities	$	200		$	215
Net cash used in investing activities	$	(48	)	$	(144	)
Net cash used in financing activities	$	(152	)	$	(74	)

Operating Activities

The decrease of $15 million or 7%, in net cash provided by operating activities for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019 was primarily driven by a decrease of $25 million in the timing of cash receipts and disbursements and changes in other working capital assets and liabilities and a decrease in net income of $18 million partially offset by an increase in adjustments for non-cash items of $28 million.

Investing Activities

The decrease of $96 million, or 67%, in net cash used in investing activities for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019 was primarily due to lower capital expenditures of $89 million, an increase in other investing cash flows of $12 million, partially offset by a decrease in return of investment in equity method affiliate of $5 million.

Financing Activities

Net cash used in financing activities increased $78 million, or 105%, for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019. Our primary financing activities consist of the following:



	Three Months Ended March 31,
	2020			2019

	(In millions)
(Decrease) increase in short-term debt	$	(45	)	$	147
Proceeds from long-term debt, net of issuance costs	—			200
Repayment of long-term debt	(250		)	—
Net proceeds (repayments) of Revolving Credit Facility	300			(250		)
Distributions	(156		)	(148		)
Cash paid for employee equity-based compensation	(1		)	(23		)

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 March 31, 2020, our sources of liquidity included:


•	cash on hand;


•	cash generated from operations;


•	proceeds from commercial paper issuances; and


•	borrowings under our Revolving Credit Facility.

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ATM Program

Distributions

On May 5, 2020, the Board of Directors declared a quarterly cash distribution of $0.16525 per common unit on all of the Partnership’s outstanding common units for the period ended March 31, 2020. The decrease in the distribution, together with announced decreases in expansion capital, maintenance capital, and operations and maintenance and general and administrative expenditures, is intended to allow liquidity and capital resources needs to be met with cash on hand and operating cash flow during the COVID-19 disruption. The distributions will be paid May 27, 2020 to unitholders of record as of the close of business on May 19, 2020. 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 May 15, 2020 to unitholders of record as of the close of business on May 5, 2020.

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 our customers and other counterparties may encounter severe financial problems that could limit our ability to collect amounts owed to us or to enforce performance of other obligations under contractual arrangements. We examine the creditworthiness of customers and other counterparties to whom we extend credit and manage our exposure to credit risk through credit analysis, approval, limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of our customers’ and other counterparties’ liquidity and limit their ability to make payment or perform on their obligations to us. For example, some of our customers have experienced significantly reduced liquidity as a result of the economic effects caused by the COVID-19 pandemic. Limitations on our ability to collect amounts owed to us or to enforce the performance of other obligations under contractual arrangements could result in the impairment of our assets, reduction of our operating cash flows and may also reduce or curtail our customers’ future use of our products and services, which could reduce our revenues.

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 March 31, 2020 are the same as those described in our Annual Report as modified for the adoption of new accounting standards disclosed in Item 1. “Financial Statements, Notes to Unaudited Condensed Consolidated Financial Statements.”

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. Direct exposure includes the impact of commodity prices on our physical commodity positions, and indirect exposure includes the impact of commodity prices on the demand for midstream services due to changes in the exploration and production of commodities. The Partnership utilizes derivatives and forward commodity sales to mitigate the effects of price changes from our direct exposure to commodity price risks. 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 9% of our total gross margin for the twelve months ended December 31, 2020 is directly exposed to changes in commodity prices, excluding the impact of hedges and contractual floors related to commodity prices in certain agreements. Since March 31, 2020, we have entered into additional derivative contracts to further manage our exposure to commodity price risk for the remaining nine months ending December 31, 2020.

Our direct exposure to commodity price risk is estimated as the potential loss in value resulting from a hypothetical 10% decline in prices over the next nine months. Based on a sensitivity analysis regarding our direct commodity exposure, a 10% decrease in prices from forecasted levels would decrease net income by approximately $6 million for natural gas and ethane and $5 million for NGLs (other than ethane) and condensate, excluding the impact of hedges, for the remaining nine months ending December 31, 2020.

The impact of the ongoing spread and economic effects of the COVID-19 pandemic, together with the recent actions of Saudi Arabia and Russia have resulted in a significant decrease in the price of natural gas, NGL and crude oil. The effects of the COVID-19 pandemic, together with the recent actions of Saudi Arabia and Russia exacerbated pre-existing price declines due to oversupply. These events may negatively impact our financial condition and results of operations as a result of our direct and indirect exposure to commodity prices. Please see Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments” for further discussion.

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 $1.2 billion outstanding borrowings under commercial paper, Revolving Credit Facility and 2019 Term Loan Agreement as of March 31, 2020, 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 $12 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 March 31, 2020. Based on such evaluation, our management has concluded that, as of March 31, 2020, 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.

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

Changes in Internal Controls Over Financial Reporting

There were no changes in our internal controls over financial reporting during the quarter ended March 31, 2020, that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting. We have not experienced any material impact to our internal controls over financial reporting despite the fact that many of our employees are working remotely due to the COVID-19 pandemic. We are continually monitoring and assessing the effects of the COVID-19 situation on our internal controls to minimize the impact on their design and operating effectiveness.

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. Except as set forth below, there have been no material changes in our risk factors from those previously disclosed under “Risk Factors” in our Annual Report.

Our businesses are dependent, in part, on the drilling and production decisions of others. In response to sharp declines in demand for oil and gas as well as commodity prices resulting from the economic impact of COVID-19, many producers have significantly reduced previously anticipated drilling and production and may make additional reductions in the future.

Our businesses are dependent on the drilling and production of natural gas and crude oil. We have no control over the level of drilling activity in our areas of operation, the amount of natural gas, NGL and crude oil reserves associated with wells connected to our systems, or the amount of natural gas and crude oil produced from the wells connected to our system. In addition, as the rate at which production from wells currently connected to our system naturally declines over time, our gross margin associated with those wells will also decline. To maintain or increase throughput levels on our gathering and transportation systems and the asset utilization rates at our natural gas processing plants, our customers must continually obtain new natural gas, NGL and crude oil supplies. The primary factors affecting our ability to obtain new supplies of natural gas, NGLs and crude oil and attract new customers to our assets are the level of successful drilling activity near our systems, our ability to compete for volumes from successful new wells and our ability to expand our capacity as needed. If we are not able to obtain new supplies of natural gas, NGLs and crude oil to replace the natural decline in volumes from existing wells, throughput on our gathering, processing, transportation and storage facilities would decline, which could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders. We have no control over producers or their drilling and production decisions, which are affected by, among other things:


•	the availability and cost of capital;


•	prevailing and projected commodity prices, including the prices of natural gas, NGLs and crude oil;


•	demand for natural gas, NGLs and crude oil;


•	levels of reserves;


•	geological considerations;


•	global or national health events, including epidemics and pandemics such as the ongoing COVID-19 pandemic;


•	environmental or other governmental regulations, including the availability of drilling permits, the regulation of hydraulic fracturing, and the regulation of air emissions; and


•	the availability of drilling rigs and other costs of production and equipment.

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Fluctuations in energy prices can also greatly affect the development of new natural gas, NGL and crude oil reserves. Drilling and production activity generally decreases as commodity prices decrease. In general terms, the prices of natural gas, NGLs, crude oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. Because of these and other factors, even if new reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. Declines in natural gas, NGL or crude oil prices can have a negative impact on exploration, development and production activity and, if sustained, could lead to decreases in such activity. For instance, the recent COVID-19 pandemic has adversely affected our business by (i) reducing the demand for natural gas, NGLs and crude oil due to reduced global and national economic activity, leading to significantly lower prices for natural gas, NGLs and crude oil, (ii) impairing the supply chain of certain of our customers for which we provide gathering and processing services, which could lead to further reduction of the utilization of our systems, and (iii) reducing producer activity across our footprint which is expected to result in reduced utilization of our services. We currently cannot predict the duration or magnitude of the effects of the COVID-19 pandemic on supply and demand for natural gas, NGLs and crude oil or the exploration, development and production activity of the producers across our areas of operation. In addition, concerns about global economic growth, as well as uncertainty regarding the timing, pace and extent of an economic recovery in the United States and abroad, have had a significant adverse impact on global financial markets and commodity prices, and sustained low natural gas, NGL or crude oil prices could also lead producers to shut in production from their existing wells. Sustained reductions in exploration or production activity in our areas of operation could lead to further reductions in the utilization of our systems, which could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders and result in the impairment of our assets.

In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems and in our processing plants, as several of the formations in the unconventional resource plays in which we operate generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Should we determine that the economics of our gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, we may reduce such capital expenditures, which could cause revenues associated with these assets to decline over time.

Natural gas, NGL and crude oil prices are volatile, and changes in these prices could adversely affect our financial position, results of operations and our ability to make cash distributions to unitholders. Prices for all three of these commodities have been adversely affected by the impact of COVID-19, with oil prices reaching historic lows.

Our financial position, results of operations and ability to make cash distributions to unitholders could be negatively affected by adverse changes in the prices of natural gas, NGLs and crude oil depending on factors that are beyond our control. These factors include demand for these commodities, which fluctuates with changes in market and economic conditions and other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, the availability of imported natural gas, LNG, NGLs and crude oil, actions taken by foreign natural gas and oil producing nations, the availability of local, intrastate and interstate transportation systems, the availability and marketing of competitive fuels, the impact of energy conservation efforts, technological advances affecting energy consumption, global or national health concerns, and the extent of governmental regulation and taxation. For example, the price of, and demand for, natural gas, NGLs and crude oil declined significantly in response to the ongoing spread and economic effects of the COVID-19 pandemic, including significant governmental measures being implemented to control the spread of the virus, including quarantines, travel restrictions and business shutdowns, and Russia’s March 2020 rejection of a plan backed by Saudi Arabia and other members of the OPEC to reduce production of crude oil in response to declining global demand. Following the rejection of the plan, Saudi Arabia significantly reduced the prices at which it sells crude oil, and both Saudi Arabia and Russia announced plans to increase production. While a coalition of 23 nations led by Saudi Arabia and Russia subsequently agreed to reduce production of crude oil by 9.7 million barrels per day in May and June, NGL and crude oil prices have remained depressed. These events, combined with the continuing COVID-19 pandemic and uncertainty regarding the length of time it will take for the United States and the rest of the world to slow the spread of COVID-19 to the point where applicable authorities are comfortable easing current restrictions on various commercial and economic activities, contributed to a sharp drop in prices for crude oil in the first and second quarters of 2020.

Our natural gas processing arrangements expose us to commodity price fluctuations. In 2019, 4%, 26%, and 70% of our processing plant inlet volumes consisted of keep-whole arrangements, percent-of-proceeds or percent-of-liquids, and fee-based, respectively. If the price at which we sell natural gas or NGLs is less than the cost at which we purchase natural gas or NGLs under these arrangements, then our financial position, results of operations and ability to make cash distributions to unitholders could be adversely affected. The Partnership uses certain derivative instruments to manage its commodity price risk exposures.

At any given time, our overall portfolio of processing contracts may reflect a net short position in natural gas (meaning that we are a net buyer of natural gas) and a net long position in NGLs (meaning that we are a net seller of NGLs). As a result, our

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financial position, results of operations and ability to make cash distributions to unitholders could be adversely affected to the extent the price of NGLs decreases in relation to the price of natural gas.

A pandemic, epidemic or outbreak of an infectious disease, such as the COVID-19 pandemic, may materially adversely affect our business.

A global or national pandemic, such as COVID-19, may cause disruptions to our business and operational plans, which may include (i) shortages of employees, (ii) unavailability of contractors and subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by, government and health authorities, including quarantines, travel restrictions and business shutdowns, to address the COVID-19 pandemic and (v) restrictions that we and our contractors and subcontractors impose, including facility shutdowns, to ensure the safety of employees and others. For example, many of our employees have been temporarily required to work remotely which, if continuing, may disrupt our operations or increase the risk of a cybersecurity incident. While it is not possible to predict their extent or duration, these disruptions may have a material adverse effect on our business, financial condition and results of operations.

The effects of COVID-19 and concerns regarding its global spread have negatively impacted domestic and international demand for natural gas, NGLs and crude oil, which has and could continue to contribute to price volatility and materially and adversely affect our customers’ operations and future production, resulting in less demand for our services and/or the reduction of commercial opportunities that might otherwise be available to us. The effects of COVID-19 have also negatively impacted domestic and international economic conditions, which has and could continue to contribute to price declines and volatility in the financial markets. While it is not possible to predict their extent or duration, these economic conditions could materially and adversely affect the availability of debt or equity financing to us, which may result in a significant reduction of our liquidity.

We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our customers could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.

Some of our customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. In addition, many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of our customers’ liquidity and limit their ability to make payment or perform on their obligations to us. For example, some of our customers have experienced significantly reduced liquidity as a result of the economic effects caused by the COVID-19 pandemic and the decision by Saudi Arabia, other OPEC members and Russia to maintain or increase production of crude oil. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Financial problems experienced by our customers could result in the impairment of our assets, reduction of our operating cash flows and may also reduce or curtail their future use of our products and services, which could reduce our revenues.

An impairment of long-lived assets, including intangible assets, equity method investments or goodwill could reduce our earnings.

Long-lived assets, including intangible assets with finite useful lives and property, plant and equipment, are evaluated for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment of long-lived assets is recognized if the carrying amount is not recoverable and exceeds fair value. During the three months ended March 31, 2020, we recorded a $16 million impairment associated with the Atoka assets, in which the Partnership owns a 50% interest in the consolidated joint venture, which is a component of the gathering and processing segment.

Equity method investments are evaluated for impairment when events or circumstances indicate that the carrying value of the investment might not be recoverable. An impairment of an equity method investment is recognized if the fair value of the investment as a whole, and not the underlying assets, has declined and the decline is other than temporary. An example of an investment that we account for under the equity method is our investment in SESH. If we enter into additional joint ventures, we could have additional equity method investments.

Goodwill is evaluated for impairment on an annual basis as well as when events or circumstances change that would more likely than not reduce the fair value of a reporting unit to below its carrying amount. An impairment of goodwill is recognized if the carrying value of a reporting unit exceeds its fair value. We recorded an impairment to goodwill of $86 million during the year ended December 31, 2019 associated with the Anadarko Basin reporting unit and $12 million during the quarter ended March 31,

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2020, associated with the Ark-La-Tex Basin reporting unit. As of March 31, 2020, we have no remaining goodwill recognized on our balance sheet for any reporting unit.

We could experience future events or circumstances that result in an impairment of long-lived assets, including intangible assets, or equity method investments. For example, the economic impact of the COVID-19 pandemic could lead to additional impairments. If we recognize an impairment, we would take an immediate non-cash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total capitalization. As a result, an impairment could have an adverse effect on our results of operations and our ability to satisfy the financial ratios or other covenants under our existing or future debt agreements.

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:	May 6, 2020	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: May 6, 2020




	/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: May 6, 2020




	/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 March 31, 2020, 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: May 6, 2020




	/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 March 31, 2020, 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: May 6, 2020




	/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)