UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

_______________________________________

FORM 10-Q

_______________________________________


☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	~~For the quarterly period ended~~	~~September 30, 2020~~

For the quarterly period ended March 31, 2021


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission File No. 1-36413

ENABLE MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)

_______________________________________

Delaware

72-1252419

(State or 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:

Title of each class

Trading symbol(s)

Name of each exchange on which registered

Common Units Representing Limited Partner Interests

ENBL

New York Stock Exchange

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~~Filer

☐☒

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

As of ~~October~~April 16, ~~2020,~~2021, there were ~~435,474,966~~435,866,139 common units outstanding.

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ENABLE MIDSTREAM PARTNERS, LP

FORM 10-Q

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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.

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GLOSSARY OF TERMS


Measurements
Bbl.			Barrel. 42 U.S. gallons of petroleum products.
Bbl/d.			Barrels per day.
Bcf.			Billion cubic feet.
Bcf/d.			Billion cubic feet per day.
Btu.			British thermal unit. When used in terms of volume, Btu refers to the amount of natural gas required to raise the temperature of one pound of water by one degree Fahrenheit at one atmospheric pressure.
MBbl.			Thousand barrels.
MBbl/d.			Thousand barrels per day.
MMBtu.			Million British thermal units.
MMcf.			Million cubic feet of natural gas.
MMcf/d.			Million cubic feet per day.
TBtu.			Trillion British thermal units.
TBtu/d.			Trillion British thermal units per day.
Abbreviations
ASC.			Accounting Standards Codification.
ASU.			Accounting Standards Update.




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.
DOT.			Department of Transportation.
EBITDA.			Earnings before interest, taxes, depreciation and amortization.
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, Missouri and Kansas.
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 to customers in the SCOOP and STACK plays of the Anadarko Basin in Oklahoma.
EOIT.			Enable Oklahoma Intrastate Transmission, LLC, formerly Enogex LLC, a wholly owned subsidiary of the Partnership that operates an approximately 2,200-mile intrastate pipeline that provides natural gas transportation and storage services to customers in Oklahoma.
EPA.			Environmental Protection Agency.

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.
FASB.			Financial Accounting Standards Board.
FERC.			Federal Energy Regulatory Commission.
GAAP.			Accounting principles generally accepted in the United States of America.




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.


MRT.			Enable Mississippi River Transmission, LLC, a wholly owned subsidiary of the Partnership that operates an approximately 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.
NGL(s).			Natural gas liquid(s), which are the hydrocarbon liquids contained within the natural gas stream including condensate.

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NYSE.			New York Stock Exchange.

OPEC.			Organization of the Petroleum Exporting Countries.
PHMSA.			Pipeline and Hazardous Materials Safety Administration.
S&P.			Standard & Poor’s Rating Services.
SCOOP.			South Central Oklahoma Oil Province.
SEC.			Securities and Exchange Commission.
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 Basin Canadian and Kingfisher Counties.

Terms and Definitions
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 initial principal amount of the Partnership’s 4.150% senior notes due 2029.
2044 Notes.			$550 million aggregate initial 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 retirement of assets, sales of assets and write-downs of materials and supplies), gain on extinguishment of debt 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.~~2020.

~~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.~~Corps.			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. United States Army Corps of Engineers.

Distribution coverage ratio.			A non-GAAP measure calculated as DCF divided by distributions related to common unitholders.





~~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 Midstream Services.			Enable ~~Oklahoma Crude~~Midstream Services, ~~LLC, formerly Velocity Holdings,~~ LLC, a wholly owned subsidiary of ~~the Partnership that provides crude oil and condensate gathering services in the SCOOP and STACK plays of the Anadarko Basin in Oklahoma.~~
~~EOIT.~~			Enable Oklahoma Intrastate Transmission, LLC, formerly Enogex LLC, a wholly owned subsidiary of the Partnership that operates an approximately 2,200-mile intrastate pipeline that provides natural gas transportation and storage services to customers in Oklahoma.Midstream Partners, LP.

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~~EPA.~~			~~United States Environmental Protection Agency.~~

EOIT Senior Notes.			$250 million aggregate principal amount of EOIT’s 6.25% senior notes that were repaid in March 2020.

~~ESCP.~~Energy Transfer.			~~Enable South Central Pipeline, LLC, formerly Velocity Pipeline Partners, LLC, in which the Partnership, through EOCS, owns~~Energy Transfer LP, 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.Delaware limited partnership.
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.
General Partner.
			Enable GP, LLC, a Delaware limited liability company, the general partner of Enable Midstream Partners, LP.
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.~~

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~~March 31 Quarterly Report.~~	~~Quarterly Report on Form 10-Q for the period ended March 31, 2020.~~
~~MBbl.~~		~~Thousand barrels.~~
~~MBbl/d.~~		~~Thousand barrels per day.~~

~~MMcf.~~Merger.		~~Million cubic feet~~The acquisition of ~~natural gas.~~the Partnership by Energy Transfer Partners, LP.

~~MMcf/d.~~Merger Agreement.		~~Million cubic feet per day.~~
		An agreement between Energy Transfer and the Partnership in which the Partnership will be acquired by Energy Transfer in an all-equity transaction, including the assumption of debt and other liabilities
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.~~


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.

AAll statements, other than statements of historical fact, included in this Form 10-Q regarding the prospects of our industry, our anticipated financial performance, management’s plans and objectives for future operations, planned capital expenditures, business prospects, outcome of regulatory proceedings, market conditions, the expected merger (the “Merger”) of the Partnership with and into Energy Transfer LP pursuant to the Agreement and Plan of Merger between us and Energy Transfer dated February 16, 2021 (the “Merger Agreement”), and other matters, may constitute forward-looking statements. In addition, 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 and in our March 31 Quarterly~~ Report. Those risk factors and other factors noted throughout this report and in our Annual ~~Report and in our March 31 Quarterly~~ 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:

•our pending Merger with Energy Transfer and the expected timing of the consummation of the Merger;

•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 COVID-19 pandemic and the economic effects of the pandemic;

•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;

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•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, including the recent U.S. Supreme Court ruling involving the Muscogee (Creek) Nation reservation in Eastern Oklahoma; and

•other factors set forth in this report and our other filings with the SEC, including our Annual ~~Report and our March 31 Quarterly~~ Report.

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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.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020

		(In millions, except per unit data)										(In millions, except per unit data)
Revenues (including revenues from affiliates (Note 13)):	Revenues (including revenues from affiliates (Note 13)):									Revenues (including revenues from affiliates (Note 13)):
Product sales	Product sales	$	280	$	320	$	764	$	1,156	Product sales		$	627	$	288
Service revenues	Service revenues	316		379		995		1,073		Service revenues		343		360
Total Revenues	Total Revenues	596		699		1,759		2,229		Total Revenues		970		648
Cost and Expenses (including expenses from affiliates (Note 13)):	Cost and Expenses (including expenses from affiliates (Note 13)):									Cost and Expenses (including expenses from affiliates (Note 13)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	250		263		653		958		Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)		519		226
Operation and maintenance	Operation and maintenance	96		105		313		307		Operation and maintenance		84		102
General and administrative	General and administrative	28		31		73		82		General and administrative		37		24
Depreciation and amortization	Depreciation and amortization	105		108		314		323		Depreciation and amortization		106		104
Impairments of property, plant and equipment and goodwill (Note 7)	Impairments of property, plant and equipment and goodwill (Note 7)	0		0		28		0		Impairments of property, plant and equipment and goodwill (Note 7)		0		28
Taxes other than income tax	Taxes other than income tax	17		17		52		52		Taxes other than income tax		18		18
Total Cost and Expenses	Total Cost and Expenses	496		524		1,433		1,722		Total Cost and Expenses		764		502
Operating Income	Operating Income	100		175		326		507		Operating Income		206		146
Other Income (Expense):	Other Income (Expense):									Other Income (Expense):
Interest expense	Interest expense	(43)		(48)		(136)		(142)		Interest expense		(42)		(47)
Equity in earnings (losses) of equity method affiliate, net		(222)		5		(211)		12
Other, net		2		1		7		2
Equity in earnings of equity method affiliate										Equity in earnings of equity method affiliate		1		6

Total Other Expense	Total Other Expense	(263)		(42)		(340)		(128)		Total Other Expense		(41)		(41)
Income (Loss) Before Income Tax		(163)		133		(14)		379
Income Before Income Tax										Income Before Income Tax		165		105
Income tax benefit	Income tax benefit	0		0		0		(1)		Income tax benefit		0		0
Net Income (Loss)		$	(163)	$	133	$	(14)	$	380
Net Income										Net Income		$	165	$	105
Less: Net income (loss) attributable to noncontrolling interest	Less: Net income (loss) attributable to noncontrolling interest	1		1		(6)		2		Less: Net income (loss) attributable to noncontrolling interest		1		(7)
Net Income (Loss) Attributable to Limited Partners		$	(164)	$	132	$	(8)	$	378
Net Income Attributable to Limited Partners										Net Income Attributable to Limited Partners		$	164	$	112
Less: Series A Preferred Unit distributions (Note 6)	Less: Series A Preferred Unit distributions (Note 6)	9		9		27		27		Less: Series A Preferred Unit distributions (Note 6)		9		9
Net Income (Loss) Attributable to Common Units (Note 5)		$	(173)	$	123	$	(35)	$	351
Net Income Attributable to Common Units (Note 5)										Net Income Attributable to Common Units (Note 5)		$	155	$	103

Basic earnings (loss) per unit (Note 5)
Common units		$	(0.40)	$	0.28	$	(0.08)	$	0.81
Diluted earnings (loss) per unit (Note 5)
Common units		$	(0.40)	$	0.28	$	(0.08)	$	0.81
Basic and diluted earnings per unit (Note 5)										Basic and diluted earnings per unit (Note 5)
Basic										Basic		$	0.35	$	0.24
Diluted										Diluted		$	0.33	$	0.19

See Notes to the Unaudited Condensed Consolidated Financial Statements

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ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020

		(In millions)										(In millions)
Net income (loss)		$	(163)	$	133	$	(14)	$	380
Net income										Net income		$	165	$	105
Other comprehensive income (loss):	Other comprehensive income (loss):									Other comprehensive income (loss):
Change in fair value of interest rate derivative instruments	Change in fair value of interest rate derivative instruments	0		(1)		(7)		(4)		Change in fair value of interest rate derivative instruments		0		(6)
Reclassification of interest rate derivative losses to net income	Reclassification of interest rate derivative losses to net income	2		0		3		0		Reclassification of interest rate derivative losses to net income		1		0
Other comprehensive income (loss)	Other comprehensive income (loss)	2		(1)		(4)		(4)		Other comprehensive income (loss)		1		(6)
Comprehensive income (loss)		(161)		132		(18)		376
Comprehensive income										Comprehensive income		166		99
Less: Comprehensive income (loss) attributable to noncontrolling interest	Less: Comprehensive income (loss) attributable to noncontrolling interest	1		1		(6)		2		Less: Comprehensive income (loss) attributable to noncontrolling interest		1		(7)
Comprehensive income (loss) attributable to Limited Partners		$	(162)	$	131	$	(12)	$	374
Comprehensive income attributable to Limited Partners										Comprehensive income attributable to Limited Partners		$	165	$	106

6See Notes to the Unaudited Condensed Consolidated Financial Statements

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ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


		September 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020

		(In millions)					(In millions)
Current Assets:	Current Assets:					Current Assets:
Cash and cash equivalents	Cash and cash equivalents	$	18	$	4	Cash and cash equivalents	$	32	$	3

Accounts receivable, net of allowance for doubtful accounts (Note 1)	Accounts receivable, net of allowance for doubtful accounts (Note 1)	229		244		Accounts receivable, net of allowance for doubtful accounts (Note 1)	284		248
Accounts receivable—affiliated companies	Accounts receivable—affiliated companies	12		25		Accounts receivable—affiliated companies	13		15
Inventory	Inventory	42		46		Inventory	44		42
Gas imbalances	Gas imbalances	38		35		Gas imbalances	49		42
Other current assets		34		35
Other current assets, net of allowance for doubtful accounts (Note 1)						Other current assets, net of allowance for doubtful accounts (Note 1)	27		31
Total current assets	Total current assets	373		389		Total current assets	449		381
Property, Plant and Equipment:	Property, Plant and Equipment:					Property, Plant and Equipment:
Property, plant and equipment	Property, plant and equipment	13,207		13,161		Property, plant and equipment	13,287		13,220
Less: Accumulated depreciation and amortization	Less: Accumulated depreciation and amortization	2,504		2,291		Less: Accumulated depreciation and amortization	2,633		2,555
Property, plant and equipment, net	Property, plant and equipment, net	10,703		10,870		Property, plant and equipment, net	10,654		10,665
Other Assets:	Other Assets:					Other Assets:
Intangible assets, net	Intangible assets, net	554		601		Intangible assets, net	523		539
Goodwill		0		12

Investment in equity method affiliate	Investment in equity method affiliate	75��		309		Investment in equity method affiliate	73		76
Other, net of allowance for doubtful accounts (Note 1)		70		85
Other						Other	65		68
Total other assets	Total other assets	699		1,007		Total other assets	661		683
Total Assets	Total Assets	$	11,775	$	12,266	Total Assets	$	11,764	$	11,729
Current Liabilities:	Current Liabilities:					Current Liabilities:
Accounts payable	Accounts payable	$	114	$	161	Accounts payable	$	158	$	149
Accounts payable—affiliated companies	Accounts payable—affiliated companies	2		1		Accounts payable—affiliated companies	1		2
Current portion of long-term debt	Current portion of long-term debt	0		251		Current portion of long-term debt	800		0
Short-term debt	Short-term debt	334		155		Short-term debt	214		250
Taxes accrued	Taxes accrued	52		32		Taxes accrued	26		34
Gas imbalances	Gas imbalances	14		19		Gas imbalances	13		19
Other	Other	128		161		Other	122		128
Total current liabilities	Total current liabilities	644		780		Total current liabilities	1,334		582
Other Liabilities:	Other Liabilities:					Other Liabilities:
Accumulated deferred income taxes, net	Accumulated deferred income taxes, net	5		4		Accumulated deferred income taxes, net	4		5
Regulatory liabilities	Regulatory liabilities	25		24		Regulatory liabilities	26		25
Other	Other	75		80		Other	67		71
Total other liabilities	Total other liabilities	105		108		Total other liabilities	97		101
Long-Term Debt	Long-Term Debt	3,950		3,969		Long-Term Debt	3,152		3,951
Commitments and Contingencies (Note 14)	Commitments and Contingencies (Note 14)					Commitments and Contingencies (Note 14)	0		0
Partners’ Equity:	Partners’ Equity:					Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at September 30, 2020 and December 31, 2019)		362		362
Common Units (435,468,668 issued and outstanding at September 30, 2020 and 435,201,365 issued and outstanding at December 31, 2019)		6,695		7,013
Series A Preferred Units (14,520,000 issued and outstanding at March 31, 2021 and December 31, 2020)						Series A Preferred Units (14,520,000 issued and outstanding at March 31, 2021 and December 31, 2020)	362		362
Common Units (435,846,766 issued and outstanding at March 31, 2021 and 435,549,892 issued and outstanding at December 31, 2020)						Common Units (435,846,766 issued and outstanding at March 31, 2021 and 435,549,892 issued and outstanding at December 31, 2020)	6,798		6,713
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(7)		(3)		Accumulated other comprehensive loss	(5)		(6)
Noncontrolling interest	Noncontrolling interest	26		37		Noncontrolling interest	26		26
Total Partners’ Equity	Total Partners’ Equity	7,076		7,409		Total Partners’ Equity	7,181		7,095
Total Liabilities and Partners’ Equity	Total Liabilities and Partners’ Equity	$	11,775	$	12,266	Total Liabilities and Partners’ Equity	$	11,764	$	11,729

7See Notes to the Unaudited Condensed Consolidated Financial Statements

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ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


		Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019			2021		2020

		(In millions)					(In millions)
Cash Flows from Operating Activities:	Cash Flows from Operating Activities:					Cash Flows from Operating Activities:
Net income (loss)		$	(14)	$	380
Net income						Net income	$	165	$	105
Adjustments to reconcile net income to net cash provided by operating activities:	Adjustments to reconcile net income to net cash provided by operating activities:					Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	Depreciation and amortization	314		323		Depreciation and amortization	106		104
Deferred income taxes		1		(1)

Impairments of property, plant and equipment and goodwill	Impairments of property, plant and equipment and goodwill	28		0		Impairments of property, plant and equipment and goodwill	0		28
Net loss on sale/retirement of assets	Net loss on sale/retirement of assets	17		5		Net loss on sale/retirement of assets	0		1
Gain on extinguishment of debt		(5)		0
Equity in (earnings) losses of equity method affiliate, net		211		(12)

Equity in earnings of equity method affiliate						Equity in earnings of equity method affiliate	(1)		(6)
Return on investment in equity method affiliate	Return on investment in equity method affiliate	14		12		Return on investment in equity method affiliate	1		6
Equity-based compensation	Equity-based compensation	10		13		Equity-based compensation	4		4
Amortization of debt costs and discount	Amortization of debt costs and discount	3		(1)		Amortization of debt costs and discount	1		0
Changes in other assets and liabilities:	Changes in other assets and liabilities:					Changes in other assets and liabilities:
Accounts receivable, net	Accounts receivable, net	14		19		Accounts receivable, net	(36)		52
Accounts receivable—affiliated companies	Accounts receivable—affiliated companies	13		(3)		Accounts receivable—affiliated companies	2		8

Inventory	Inventory	4		3		Inventory	(2)		3
Gas imbalance assets	Gas imbalance assets	(3)		6		Gas imbalance assets	(7)		(1)
Other current assets		0		(2)
Other current assets, net						Other current assets, net	2		(6)
Other assets	Other assets	4		8		Other assets	2		1
Accounts payable	Accounts payable	(47)		(108)		Accounts payable	11		(59)
Accounts payable—affiliated companies	Accounts payable—affiliated companies	1		(2)		Accounts payable—affiliated companies	(1)		1
Gas imbalance liabilities	Gas imbalance liabilities	(5)		(5)		Gas imbalance liabilities	(6)		(2)
Other current liabilities	Other current liabilities	(14)		64		Other current liabilities	(14)		(35)
Other liabilities	Other liabilities	(3)		(8)		Other liabilities	(4)		(4)
Net cash provided by operating activities	Net cash provided by operating activities	543		691		Net cash provided by operating activities	223		200
Cash Flows from Investing Activities:	Cash Flows from Investing Activities:					Cash Flows from Investing Activities:
Capital expenditures	Capital expenditures	(152)		(353)		Capital expenditures	(80)		(54)

Proceeds from sale of assets	Proceeds from sale of assets	19		1		Proceeds from sale of assets	1		0
Proceeds from insurance		1		0

Return of investment in equity method affiliate	Return of investment in equity method affiliate	9		8		Return of investment in equity method affiliate	3		4
Other, net	Other, net	3		(9)		Other, net	1		2
Net cash used in investing activities	Net cash used in investing activities	(120)		(353)		Net cash used in investing activities	(75)		(48)
Cash Flows from Financing Activities:	Cash Flows from Financing Activities:					Cash Flows from Financing Activities:
Increase (decrease) in short-term debt		179		(467)
Proceeds from long-term debt, net of issuance costs		0		1,544
Decrease in short-term debt						Decrease in short-term debt	(36)		(45)

Repayment of long-term debt	Repayment of long-term debt	(267)		(700)		Repayment of long-term debt	0		(250)
Proceeds from Revolving Credit Facility	Proceeds from Revolving Credit Facility	869		0		Proceeds from Revolving Credit Facility	0		340
Repayment of Revolving Credit Facility	Repayment of Revolving Credit Facility	(869)		(250)		Repayment of Revolving Credit Facility	0		(40)

Distributions to common unitholders	Distributions to common unitholders	(288)		(420)		Distributions to common unitholders	(72)		(144)
Distributions to preferred unitholders	Distributions to preferred unitholders	(27)		(27)		Distributions to preferred unitholders	(9)		(9)
Distributions to non-controlling interests	Distributions to non-controlling interests	(5)		(3)		Distributions to non-controlling interests	(1)		(3)
Cash paid for employee equity-based compensation	Cash paid for employee equity-based compensation	(1)		(24)		Cash paid for employee equity-based compensation	(1)		(1)
Net cash used in financing activities	Net cash used in financing activities	(409)		(347)		Net cash used in financing activities	(119)		(152)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash		14		(9)
Net Increase in Cash, Cash Equivalents and Restricted Cash						Net Increase in Cash, Cash Equivalents and Restricted Cash	29		0
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	Cash, Cash Equivalents and Restricted Cash at Beginning of Period	4		22		Cash, Cash Equivalents and Restricted Cash at Beginning of Period	3		4
Cash, Cash Equivalents and Restricted Cash at End of Period	Cash, Cash Equivalents and Restricted Cash at End of Period	$	18	$	13	Cash, Cash Equivalents and Restricted Cash at End of Period	$	32	$	4

See Notes to the Unaudited Condensed Consolidated Financial Statements

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ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

(Unaudited)


		Nine Months Ended September 30, 2020													Three Months Ended March 31, 2021
		Series A Preferred Units			Common Units			Accumulated Other Comprehensive Loss		Noncontrolling Interest		Total Partners’ Equity			Series A Preferred Units			Common Units			Accumulated Other Comprehensive Loss		Noncontrolling Interest		Total Partners’ Equity
		Units	Value		Units	Value		Value		Value		Value			Units	Value		Units	Value		Value		Value		Value

		(In millions)													(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		—	—		0	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
Balance as of December 31, 2020														Balance as of December 31, 2020	15	$	362	435	$	6,713	$	(6)	$	26	$	7,095
Net income	Net income	—	9		—	35		—		0		44		Net income	—	9		—	155		—		1		165

Distributions		—	(9)		—	(72)		—		0		(81)
Equity-based compensation, net of units for employee taxes		—	—		0	2		—		—		2
Balance as of June 30, 2020		15	$	362	435	$	6,937	$	(9)	$	27	$	7,317
Net income (loss)		—	9		—	(173)		—		1		(163)
Other comprehensive income	Other comprehensive income	—	—		—	—		2		—		2		Other comprehensive income	—	—		—	—		1		—		1
Distributions	Distributions	—	(9)		—	(72)		—		(2)		(83)		Distributions	—	(9)		—	(72)		—		(1)		(82)
Equity-based compensation, net of units for employee taxes	Equity-based compensation, net of units for employee taxes	—	—		0	3		—		—		3		Equity-based compensation, net of units for employee taxes	—	—		1	2		—		—		2
Balance as of September 30, 2020		15	$	362	435	$	6,695	$	(7)	$	26	$	7,076
Balance as of March 31, 2021														Balance as of March 31, 2021	15	$	362	436	$	6,798	$	(5)	$	26	$	7,181


		Nine Months Ended September 30, 2019													Three Months Ended March 31, 2020
		Series A Preferred Units			Common Units			Accumulated Other Comprehensive Loss		Noncontrolling Interest		Total Partners’ Equity			Series A Preferred Units			Common Units			Accumulated Other Comprehensive Loss		Noncontrolling Interest		Total Partners’ Equity
		Units	Value		Units	Value		Value		Value		Value			Units	Value		Units	Value		Value		Value		Value

		(In millions)													(In millions)
Balance as of December 31, 2018		15	$	362	433	$	7,218	$	0	$	38	$	7,618
Net income		—	9		—	113		—		1		123

Distributions		—	(9)		—	(138)		—		(1)		(148)
Equity-based compensation, net of units for employee taxes		—	—		2	(10)		—		—		(10)
Balance as of March 31, 2019		15	$	362	435	$	7,183	$	0	$	38	$	7,583
Net income		—	9		—	115		—		0		124
Balance as of December 31, 2019														Balance as of December 31, 2019	15	$	362	435	$	7,013	$	(3)	$	37	$	7,409
Net income (loss)														Net income (loss)	—	9		—	103		—		(7)		105
Other comprehensive loss	Other comprehensive loss	—	—		—	—		(3)		—		(3)		Other comprehensive loss	—	—		—	—		(6)		—		(6)
Distributions	Distributions	—	(9)		—	(138)		—		(1)		(148)		Distributions	—	(9)		—	(144)		—		(3)		(156)
Equity-based compensation, net of units for employee taxes	Equity-based compensation, net of units for employee taxes	—	—		0	3		—		—		3		Equity-based compensation, net of units for employee taxes	—	—		0	3		—		—		3
Balance as of June 30, 2019		15	$	362	435	$	7,163	$	(3)	$	37	$	7,559
Net income		—	9		—	123		—		1		133
Other comprehensive loss		—	—		—	—		(1)		—		(1)
Distributions		—	(9)		—	(144)		—		(1)		(154)
Equity-based compensation, net of units for employee taxes		—	—		0	3		—		—		3
Balance as of September 30, 2019		15	$	362	435	$	7,145	$	(4)	$	37	$	7,540
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)														Impact of adoption of financial instruments-credit losses accounting standard (Note 1)	—	—		—	(3)		—		—		(3)
Balance as of March 31, 2020														Balance as of March 31, 2020	15	$	362	435	$	6,972	$	(9)	$	27	$	7,352

See Notes to the Unaudited Condensed Consolidated Financial Statements

910

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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 (the Partnership) is a Delaware limited partnership whose assets and operations are organized into 2 reportable segments: (i) gathering and processing and (ii) transportation and storage. ~~The~~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. 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~~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. 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 2 representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership’s Chief Executive Officer and 3 independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP.

As of ~~September 30, 2020,~~March 31, 2021, CenterPoint Energy held approximately 53.7% or 233,856,623 of the Partnership’s common units, and OGE Energy held approximately 25.5% or 110,982,805 of the Partnership’s common units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. The limited partner interests of the Partnership have limited voting rights on matters affecting the business. As such, limited partners do not have rights to elect the Partnership’s general partner on an annual or continuing basis and may not remove Enable GP, its current general partner, without at least a 75% vote by all unitholders, including all units held by the Partnership’s limited partners, and Enable GP and its affiliates, voting together as a single class.

As of ~~September 30, 2020,~~March 31, 2021, the Partnership owned a 50% interest in SESH. See Note 8 for further discussion of SESH. For the ~~nine~~three months ended ~~September 30, 2020,~~March 31, 2021, the Partnership ~~held~~owned a 50% ownership in Atoka and consolidated Atoka in ~~its~~the accompanying 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~~the accompanying Condensed Consolidated Financial Statements as EOCS acted as the managing member of ESCP and had control over the operations of ESCP.

Merger Agreement

On February 17, 2021, the Partnership and Energy Transfer announced their entry into a Merger Agreement, whereby the Partnership will be acquired by Energy Transfer in an all-equity transaction, including the assumption of debt and other liabilities. Under the terms of the Merger Agreement, which has been unanimously approved by the Boards of Directors of both companies, Partnership common unitholders will receive 0.8595 of an Energy Transfer common unit for each Partnership common unit. Each of the Partnership’s Series A Preferred Units will be exchanged for 0.0265 Series G preferred units of Energy Transfer. The transaction will also include a $10 million cash payment for the Partnership’s general partner.

Generally, the Merger, including the receipt of equity consideration by common unitholders is expected to be treated as a tax-free transaction subject to certain exceptions as described in a Registration Statement on Form S-4 filed by Energy Transfer. The transaction, which is expected to close in mid-2021, is subject to customary closing conditions. CenterPoint Energy and OGE Energy, who collectively own approximately 79% of the outstanding Partnership common units, delivered their consents to the transaction. The Merger Agreement includes certain customary restrictions on the Partnership until closing of the Merger, such as limitations on distributions, equity issuances, and incurring and prepaying indebtedness. If the Merger does not occur, under certain circumstances, the Partnership may be required to pay Energy Transfer a termination fee of $97.5 million. Until the approval by unitholders and subsequent closing, we must continue to operate the Partnership as a stand-alone company.

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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 COVID-19 pandemic and the economic effects of the pandemic which have resulted in a substantial decrease in natural gas, NGLs and crude oil prices.

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For a description of the Partnership’s reportable segments, see Note 16.

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.

Sales and Retirements of Assets

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. We did not recognize a gain or loss on this transaction.

In April 2020, we sustained damage to an approximately 100-mile gas gathering system in the Ark-La-Tex Basin of our gathering and processing segment. We have ceased operation of this system and are in the process of retiring it. We recognized a loss on retirement of approximately $20 million during the nine months ended September 30, 2020, which is included in Operation and maintenance expense in the Condensed Consolidated Statements of Income.

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 forecast 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 forecast economic conditions over the assets contractual lives. The following table summarizes the required allowance for doubtful accounts.

September 30, 2020 January 1, 2020
(In millions)
Accounts receivable $ 2 $ 2
Other assets 3 3
Total Allowance for doubtful accounts $ 5 $ 5

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	March 31, 2021		December 31, 2020

	(In millions)
Accounts receivable	$	4	$	1
Other assets	3		3
Total Allowance for doubtful accounts	$	7	$	4

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 ~~$2 million and 0 during the three months ended September 30, 2020 and 2019, respectively,~~

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~~and $9~~$1 million and $6 million during the ~~nine~~three months ended ~~September 30,~~March 31, 2021 and 2020, ~~and 2019,~~ respectively.

~~Assessing~~ Impairment of ~~Property, Plant and Equipment, Goodwill and Investment in Equity Method Affiliate~~Long-Lived Assets (including Intangible Assets)

The Partnership periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles other than goodwill, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. For more information, see Note 7.

Impairment of Goodwill

The Partnership assesses its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. The Partnership utilizes the market or income approaches to estimate the fair value of the reporting unit, also giving consideration to the alternative cost approach. Under the market approach, historical and current year forecasted cash flows are multiplied by a market multiple to determine fair value. Under the income approach, anticipated cash flows over a period of years plus a terminal value are discounted to present value using appropriate discount rates. The resulting fair value of the reporting unit is then compared to the carrying amount of the reporting unit and an impairment charge is recorded to goodwill for the difference. The Partnership performs its goodwill impairment testing at the reporting unit, which is one level below the transportation and storage and gathering and processing reportable segment level. For more information, see Note 7.

The Partnership evaluates its Investment in equity method affiliate for impairment when factors indicate that an other than temporary decrease in the value of its investment has occurred and the carrying amount of its investment may not be recoverable. The Partnership utilizes the market or income approaches to estimate the fair value of the investment, also giving consideration to the alternative cost approach. Under the market approach, historical and current year forecasted cash flows are multiplied by a market multiple to determine fair value. Under the income approach, anticipated cash flows over a period of years plus a terminal value are discounted to present value using appropriate discount rates. The resulting fair value of the investment is then compared to the carrying amount of the investment and an impairment charge is recorded to Equity in earnings (losses) of equity method affiliate, net for the difference. Any basis difference between our recognized Investment in equity method affiliate and the underlying financial statements of the affiliate are assigned to the applicable net assets of the affiliate. For more information, see Note 8.

(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~~adopted ASU 2020-04 during the year ended December 31, 2020. The implementation had no material impact ~~this~~on the Consolidated Financial Statements and related disclosures.

In January 2021, the FASB issued ASU ~~will have~~No. 2021-01, “Reference Rate Reform (Topic 848): Scope.” This standard clarifies that certain optional expedients and exceptions in ASC 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition. ASU 2021-01 also amends the expedients and exceptions in ASC 848 to capture the incremental consequences of the scope clarification and to tailor the existing guidance to derivative instruments affected by the discounting transition. ASU 2021-01 was effective upon issuance and generally can be applied through December 31, 2022. The Partnership adopted ASU 2021-01 during three months ended March 31, 2021. The implementation had no material impact on ~~our~~the Condensed Consolidated Financial Statements and related disclosures.

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(3) Revenues

The following tables disaggregate total revenues by major source from contracts with customers and the gain (loss) on derivative activity for the three ~~and nine~~ months ended ~~September 30, 2020~~March 31, 2021 and ~~2019.~~2020.

Three Months Ended September 30, 2020
Gathering and
Processing Transportation
and Storage Eliminations Total
(In millions)
Revenues:
Product sales:
Natural gas $ 58 $ 77 $ (68) $ 67
Natural gas liquids 208 2 (2) 208
Condensate 15 0 0 15
Total revenues from natural gas, natural gas liquids, and condensate 281 79 (70) 290
Loss on derivative activity (10) 0 0 (10)
Total Product sales $ 271 $ 79 $ (70) $ 280
Service revenues:
Demand revenues $ 32 $ 116 $ 0 $ 148
Volume-dependent revenues 160 10 (2) 168
Total Service revenues $ 192 $ 126 $ (2) $ 316
Total Revenues $ 463 $ 205 $ (72) $ 596

Three Months Ended September 30, 2019
Gathering and
Processing Transportation
and Storage Eliminations Total
(In millions)
Revenues:
Product sales:
Natural gas $ 69 $ 95 $ (69) $ 95
Natural gas liquids 191 5 (5) 191
Condensate 26 0 0 26
Total revenues from natural gas, natural gas liquids, and condensate 286 100 (74) 312
Gain on derivative activity 8 0 0 8
Total Product sales $ 294 $ 100 $ (74) $ 320
Service revenues:
Demand revenues $ 97 $ 119 $ 0 $ 216
Volume-dependent revenues 151 15 (3) 163
Total Service revenues $ 248 $ 134 $ (3) $ 379
Total Revenues $ 542 $ 234 $ (77) $ 699


	Three Months Ended March 31, 2021
	Gathering and Processing		Transportation and Storage		Eliminations		Total

	(In millions)
Revenues:
Product sales:
Natural gas	$	112	$	330	$	(130)	$	312
Natural gas liquids	297		3		(3)		297
Condensate	32		0		0		32
Total revenues from natural gas, natural gas liquids, and condensate	441		333		(133)		641
Loss on derivative activity	(13)		(1)		0		(14)
Total Product sales	$	428	$	332	$	(133)	$	627
Service revenues:
Demand revenues	$	26	$	127	$	0	$	153
Volume-dependent revenues	170		23		(3)		190
Total Service revenues	$	196	$	150	$	(3)	$	343
Total Revenues	$	624	$	482	$	(136)	$	970

~~Table of Contents~~

Nine Months Ended September 30, 2020
Gathering and
Processing Transportation
and Storage Eliminations Total
(In millions)
Revenues:
Product sales:
Natural gas $ 161 $ 207 $ (181) $ 187
Natural gas liquids 523 7 (7) 523
Condensate 49 0 0 49
Total revenues from natural gas, natural gas liquids, and condensate 733 214 (188) 759
Gain (loss) on derivative activity 6 (1) 0 5
Total Product sales $ 739 $ 213 $ (188) $ 764
Service revenues:
Demand revenues $ 105 $ 371 $ 0 $ 476
Volume-dependent revenues 487 38 (6) 519
Total Service revenues $ 592 $ 409 $ (6) $ 995
Total Revenues $ 1,331 $ 622 $ (194) $ 1,759


		Nine Months Ended September 30, 2019									Three Months Ended March 31, 2020
		Gathering and Processing		Transportation and Storage		Eliminations		Total			Gathering and Processing		Transportation and Storage		Eliminations		Total

		(In millions)									(In millions)
Revenues:	Revenues:									Revenues:
Product sales:	Product sales:									Product sales:
Natural gas	Natural gas	$	291	$	365	$	(305)	$	351	Natural gas	$	56	$	73	$	(60)	$	69
Natural gas liquids	Natural gas liquids	698		16		(16)		698		Natural gas liquids	172		2		(2)		172
Condensate	Condensate	93		0		0		93		Condensate	27		0		0		27
Total revenues from natural gas, natural gas liquids, and condensate	Total revenues from natural gas, natural gas liquids, and condensate	1,082		381		(321)		1,142		Total revenues from natural gas, natural gas liquids, and condensate	255		75		(62)		268
Gain on derivative activity	Gain on derivative activity	14		0		0		14		Gain on derivative activity	20		0		0		20
Total Product sales	Total Product sales	$	1,096	$	381	$	(321)	$	1,156	Total Product sales	$	275	$	75	$	(62)	$	288
Service revenues:	Service revenues:									Service revenues:
Demand revenues	Demand revenues	$	225	$	373	$	0	$	598	Demand revenues	$	39	$	142	$	0	$	181
Volume-dependent revenues	Volume-dependent revenues	438		48		(11)		475		Volume-dependent revenues	163		17		(1)		179
Total Service revenues	Total Service revenues	$	663	$	421	$	(11)	$	1,073	Total Service revenues	$	202	$	159	$	(1)	$	360
Total Revenues	Total Revenues	$	1,759	$	802	$	(332)	$	2,229	Total Revenues	$	477	$	234	$	(63)	$	648

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. In May 2020, $21 million previously held in reserve was refunded to customers, which is inclusive of interest.

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Accounts Receivable

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


		September 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020

		(In millions)					(In millions)
Accounts Receivable:	Accounts Receivable:					Accounts Receivable:
Customers	Customers	$	233	$	239	Customers	$	272	$	245
Contract assets (1)	Contract assets (1)	3		18		Contract assets (1)	21		12
Non-customers	Non-customers	5		12		Non-customers	4		6
Total Accounts Receivable (2)	Total Accounts Receivable (2)	$	241	$	269	Total Accounts Receivable (2)	$	297	$	263

____________________

(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 contract assets related to firm service transportation contracts with tiered rates of $9$10 million as of ~~September 30, 2020~~March 31, 2021 and $6$9 million as of December 31, ~~2019,~~2020, which are reflected in Other Assets.

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

Contract Liabilities

Our contract liabilities primarily consist of prepayments received from customers for which the good or service has not yet been provided in connection with the prepayment.

The table below summarizes the change in the contract liabilities.

September 30, 2020 December 31, 2019 Amounts recognized in revenues
(In millions)
Deferred revenues (1)
$ 44 $ 48 $ 23


	March 31, 2021		December 31, 2020

	(In millions)
Deferred revenues, beginning of period (1)	$	44	$	48
Amounts recognized in revenues related to the beginning balance	(17)		(25)
Net additions	16		21
Deferred revenues, end of period (1)	$	43	$	44

____________________

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

The table below summarizes the timing of recognition of these contract liabilities as of ~~September 30, 2020.~~March 31, 2021.

2020 2021 2022 2023 2024 and After
(In millions)
Deferred revenues (1)
$ 17 $ 7 $ 6 $ 6 $ 8


	2021		2022		2023		2024		2025 and After
	(In millions)
Deferred revenues (1)	$	20	$	7	$	7	$	7	$	2

____________________

(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.

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The table below summarizes the timing of recognition of the remaining performance obligations as of ~~September 30, 2020.~~March 31, 2021.


		2020		2021		2022		2023		2024 and After			2021		2022		2023		2024		2025 and After
		(In millions)											(In millions)
Transportation and Storage	Transportation and Storage	$	119	$	419	$	350	$	326	$	1,187	Transportation and Storage	$	325	$	393	$	353	$	266	$	959
Gathering and Processing	Gathering and Processing	31		121		123		121		313		Gathering and Processing	93		123		121		101		213
Total remaining performance obligations	Total remaining performance obligations	$	150	$	540	$	473	$	447	$	1,500	Total remaining performance obligations	$	418	$	516	$	474	$	367	$	1,172

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(4) Leases

The table below summarizes the operating leases included in the Condensed Consolidated Balance Sheets.


		Balance Sheet Location	September 30, 2020		December 31, 2019			Balance Sheet Location	March 31, 2021		December 31, 2020

			(In millions)						(In millions)
Operating lease asset	Operating lease asset	Other Assets	$	27	$	37	Operating lease asset	Other Assets	$	24	$	25
Total right-of-use assets	Total right-of-use assets		$	27	$	37	Total right-of-use assets		$	24	$	25

Operating lease liabilities	Operating lease liabilities	Other Current Liabilities	$	5	$	9	Operating lease liabilities	Other Current Liabilities	$	4	$	4
Operating lease liabilities	Operating lease liabilities	Other Liabilities	25		31		Operating lease liabilities	Other Liabilities	23		24
Total lease liabilities	Total lease liabilities		$	30	$	40	Total lease liabilities		$	27	$	28

As of ~~September 30, 2020,~~March 31, 2021, all lease obligations outstanding were classified as operating leases. Therefore, all cash flows are reflected in Cash Flows from Operating Activities.

The following table presents the Partnership’s rental costs associated with field equipment and buildings.

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions)
Rental Costs:
Field equipment $ 3 $ 6 $ 12 $ 18
Office space 1 1 3 5


	Three Months Ended March 31,
		2021		2020

		(In millions)
Rental Costs:
Field equipment		$	3	$	5
Office space		1		1

As of ~~September 30, 2020,~~March 31, 2021, the weighted average remaining lease term is ~~7.0~~6.5 years and the weighted average discount rate is ~~5.47%~~5.49%.

The following table presents the Partnership’s lease cost.


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020

		(In millions)										(In millions)
Lease Cost:	Lease Cost:									Lease Cost:
Operating lease cost	Operating lease cost	$	2	$	2	$	5	$	7	Operating lease cost		$	1	$	2
Short-term lease cost	Short-term lease cost	2		4		9		15		Short-term lease cost		2		3
Variable lease cost	Variable lease cost	0		1		1		1		Variable lease cost		1		1
Total Lease Cost	Total Lease Cost	$	4	$	7	$	15	$	23	Total Lease Cost		$	4	$	6

The Partnership recorded 0 short-term lease costs ~~of $1 million~~ in the transportation and storage reportable segment during the three ~~and nine~~ months ended ~~September 30, 2019.~~March 31, 2021 and 2020. All ~~other~~ lease costs were included in the gathering and processing reportable segment.

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Under ASC 842, as of ~~September 30, 2020~~March 31, 2021, the Partnership has operating lease obligations expiring at various dates. Undiscounted cash flows for ~~non-cancellable~~ operating lease liabilities are as follows:


		Non-cancellable operating leases			Non-cancellable operating leases

		(In millions)			(In millions)
Year Ended December 31,
2020 - remainder		$	2
2021		6
Year Ending December 31,				Year Ending December 31,
2021 - remainder				2021 - remainder	$	4
2022	2022	5		2022	5
2023	2023	5		2023	6
2024	2024	4		2024	4
2025	2025	3		2025	3
After 2025		8
2026				2026	2
After 2026				After 2026	6
Total	Total	33		Total	30
Impact of the applicable discount rate		(3)
Less: impact of the applicable discount rate				Less: impact of the applicable discount rate	3
Total lease liabilities	Total lease liabilities	$	30	Total lease liabilities	$	27

(5) Earnings Per Limited Partner Unit

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

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions, except per unit data)
Net income (loss) $ (163) $ 133 $ (14) $ 380
Net income (loss) attributable to noncontrolling interest 1 1 (6) 2
Series A Preferred Unit distributions 9 9 27 27
General partner interest in net income 0 0 0 0
Net income (loss) available to common units $ (173) $ 123 $ (35) $ 351
Net income (loss) allocable to common units $ (173) $ 123 $ (35) $ 351
Dilutive effect of Series A Preferred Unit distributions (2)
0 0 0 0
Diluted net income (loss) allocable to common units $ (173) $ 123 $ (35) $ 351
Basic weighted average number of common units outstanding (1)
437 437 437 436
Dilutive effect of Series A Preferred Units (2)
0 0 0 0
Dilutive effect of performance units (3)
— — — —
Diluted weighted average number of common units outstanding 437 437 437 436
Basic earnings (loss) per unit
Common units $ (0.40) $ 0.28 $ (0.08) $ 0.81
Diluted earnings (loss) per unit
Common units $ (0.40) $ 0.28 $ (0.08) $ 0.81


	Three Months Ended March 31,
		2021		2020

		(In millions, except per unit data)
Net income		$	165	$	105
Net income (loss) attributable to noncontrolling interest		1		(7)
Series A Preferred Unit distributions		9		9

Net income available to common units		$	155	$	103

Net income allocable to common units		$	155	$	103
Dilutive effect of Series A Preferred Unit distributions		9		9
Diluted net income allocable to common units		$	164	$	112



Basic weighted average number of common units outstanding (1)		438		437
Dilutive effect of Series A Preferred Units		57		144
Dilutive effect of performance units (2)		0		0
Diluted weighted average number of common units outstanding		495		581

Basic and diluted earnings per unit
Basic		$	0.35	$	0.24
Diluted		$	0.33	$	0.19

____________________

(1)Basic weighted average number of outstanding common units includes approximately 2000000 time-based phantom units for ~~both~~each of the three months ended ~~September 30, 2020~~March 31, 2021 and ~~2019, and 2000000 and 1000000 time-based phantom units for the nine months ended September 30, 2020 and 2019, respectively.~~2020.

(2)For the three and nine months ended September 30, 2020 and 2019, the issuance of “if-converted” common units attributable to the Series A Preferred Units were excluded in the calculation of diluted earnings (loss) per unit as the impact was anti-dilutive.

~~Table of Contents~~

~~(3)The contingent effect of performance unit awards is anti-dilutive for the three and nine months ended September 30, 2020.~~ The dilutive effect of the performance unit awards was less than $0.01 per unit during the three ~~and nine~~ months ended ~~September 30, 2019.~~March 31, 2021 and 2020.

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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~~2021 and ~~2019~~2020 (in millions, except for per unit amounts):

Three Months Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution
September 30, 2020 (1)
November 17, 2020 November 24, 2020 $ 0.16525 $ 72
June 30, 2020 August 18, 2020 August 25, 2020 0.16525 72
March 31, 2020 May 19, 2020 May 27, 2020 0.16525 72
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

Three Months Ended

Record Date

Payment Date

Per Unit Distribution

Total Cash Distribution

March 31, 2021(1)

May 13, 2021

May 25, 2021

0.16525

December 31, 2020

February 22, 2021

March 1, 2021

0.16525

September 30, 2020

November 17, 2020

November 24, 2020

0.16525

June 30, 2020

August 18, 2020

August 25, 2020

0.16525

March 31, 2020

May 19, 2020

May 27, 2020

0.16525

_____________________

(1)The Board of Directors declared a $0.16525 per common unit cash distribution on ~~November 3, 2020,~~April 26, 2021, to be paid on ~~November 24, 2020~~May 25, 2021 to common unitholders of record at the close of business on ~~November 17, 2020.~~May 13, 2021.

Holders of the Series A Preferred Units receive a quarterly cash distribution on a non-cumulative basis if and when declared by the General Partner, and subject to certain adjustments, equal to an annual rate of 10% on the stated liquidation preference of $25.00 from the date of original issue, February 18, 2016, to, but not including, the five-year anniversary of the original issue date, February 18, 2021. Thereafter, the holders receive a quarterly cash distribution based on a percentage of the stated liquidation preference equal to the sum of the three-month LIBOR plus 8.5%, which was 8.7375% for the relevant days in the three months ended March 31, 2021.

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during ~~2020~~2021 and ~~2019~~2020 (in millions, except for per unit amounts):

Three Months Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution
September 30, 2020 (1)
November 3, 2020 November 13, 2020 $ 0.625 $ 9
June 30, 2020 August 4, 2020 August 14, 2020 0.625 9
March 31, 2020 May 5, 2020 May 15, 2020 0.625 9
December 31, 2019 February 7, 2020 February 14, 2020 0.625 9
September 30, 2019 November 5, 2019 November 14, 2019 0.625 9
June 30, 2019 August 2, 2019 August 14, 2019 0.625 9
March 31, 2019 April 29, 2019 May 15, 2019 0.625 9

Three Months Ended

Record Date

Payment Date

Per Unit Distribution

Total Cash Distribution

March 31, 2021(1)

April 26, 2021

May 14, 2021

0.5873

December 31, 2020

February 12, 2021

0.625

September 30, 2020

November 3, 2020

November 13, 2020

0.625

June 30, 2020

August 4, 2020

August 14, 2020

0.625

March 31, 2020

May 5, 2020

May 15, 2020

0.625

_____________________

(1)The Board of Directors declared a ~~$0.625~~$0.5873 per Series A Preferred Unit cash distribution on ~~November 3, 2020,~~April 26, 2021, to be paid on ~~November 13, 2020,~~May 14, 2021, to Series A Preferred unitholders of record at the close of business on ~~November 3, 2020.~~April 26, 2021.

~~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 registration statement filed with the SEC for the ATM Program expired on May 12, 2020, and the Partnership did not file a replacement registration statement.

(7) Impairments of Property, Plant and Equipment and Goodwill

Impairment of Property, Plant and Equipment

The Partnership periodically evaluates property, plant and equipment for impairment 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 COVID-19 pandemic and the economic effects of the pandemic, together with the dispute over crude oil production levels

~~Table of Contents~~

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 fully recoverable. The Partnership utilized the income approach (generally accepted valuation approach) to estimate the fair value of these assets. The primary inputs ~~are~~were 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 of property, plant and equipment and goodwill on the Condensed Consolidated Statements of Income during the ~~nine~~three months ended ~~September 30,~~March 31, 2020.

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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 commodity price declines due to the existing oversupply of crude oil, NGLs and natural gas were exacerbated by the ongoing COVID-19 pandemic and the economic effects of the pandemic, in addition to the dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia in the first quarter. 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~~had remained significantly lower than pre-pandemic levels. Amid such crude oil, NGL and natural gas price declines, producers ~~have~~had 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~~had 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 of property, plant and equipment and goodwill on the Condensed Consolidated Statements of Income for the ~~nine~~three months ended ~~September 30,~~March 31, 2020. The Partnership had 0 goodwill recorded as of March 31, 2021 and December 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 $ 0 $ 12
Goodwill impairment (12) 0 (12)
Balance as of September 30, 2020 $ 0 $ 0 $ 0

(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.

At September 30, 2020, the Partnership estimated the fair value of its investment in SESH was below the carrying value and concluded the decline in value was other than temporary due to the expiration of a transportation contract and the current status of renewal negotiations. As a result, the Partnership recorded a $225 million impairment on its investment in SESH for the three and nine months ended September 30, 2020, which is included in Equity in earnings (losses) of equity method

~~Table of Contents~~

affiliate, net in the Partnership’s Condensed Consolidated Statements of Income. The impairment analysis of the Partnership’s investment in SESH compared the estimated fair value of the investment to its carrying value. The fair value of the investment was determined using multiple valuation methodologies under both the market and income approaches. Due to the significant unobservable estimates and assumptions required, the Partnership concluded that the fair value estimate should be classified as a Level 3 measurement within the fair value hierarchy. The basis difference for our investment in SESH has been assigned to its property, plant and equipment and will be amortized over its approximately 50-year remaining useful life. See Note 1 for further information concerning the method used to evaluate and measure the impairment on the Partnership’s investment in SESH.

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 $3$2 million and $2$6 million during the three months ended ~~September 30,~~March 31, 2021 and 2020, ~~and 2019, respectively, and $11 million and $12 million during the nine months ended September 30, 2020 and 2019,~~ respectively, associated with these service agreements.

The Partnership includes equity in earnings of equity method affiliate, net 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 ~~Impairment of equity method affiliate investment~~ and Distributions from equity method affiliate received.


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020

		(In millions)										(In millions)
Equity in earnings of equity method affiliate	Equity in earnings of equity method affiliate	$	3	$	5	$	14	$	12	Equity in earnings of equity method affiliate		$	1	$	6
Impairment of equity method affiliate investment		(225)		0		(225)		0
Equity in earnings (losses) of equity method affiliate, net		$	(222)	$	5	$	(211)	$	12

Distributions from equity method affiliate (1)	Distributions from equity method affiliate (1)	$	4	$	4	$	23	$	20	Distributions from equity method affiliate (1)		4		10

___________________

(1)Distributions from equity method affiliate includes a ~~$14~~$1 million and ~~$12~~$6 million return on investment and a $9$3 million and $8$4 million return of investment for the ~~nine~~three months ended ~~September 30,~~March 31, 2021 and 2020, ~~and 2019,~~ respectively.

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The following table includes the summarized financial information of SESH.


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020

		(In millions)										(In millions)
Income Statements:	Income Statements:									Income Statements:
Revenues	Revenues	$	24	$	27	$	79	$	81	Revenues		$	15	$	27
Operating income	Operating income	11		15		40		37		Operating income		4		16
Net income		6		10		27		24
Net income (loss)										Net income (loss)		(1)		11

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(9) Debt

The following table presents the Partnership’s outstanding debt.


		September 30, 2020						December 31, 2019							March 31, 2021						December 31, 2020
		Outstanding Principal		Discount (1)		Total Debt		Outstanding Principal		Premium (Discount) (1)		Total Debt			Outstanding Principal		Discount (1)		Total Debt		Outstanding Principal		Discount (1)		Total Debt

		(In millions)													(In millions)
Commercial Paper	Commercial Paper	$	334	$	0	$	334	$	155	$	0	$	155	Commercial Paper	$	214	$	0	$	214	$	250	$	0	$	250
Revolving Credit Facility		0		0		0		0		0		0

2019 Term Loan Agreement	2019 Term Loan Agreement	800		0		800		800		0		800		2019 Term Loan Agreement	800		0		800		800		0		800
2024 Notes	2024 Notes	600		0		600		600		0		600		2024 Notes	600		0		600		600		0		600
2027 Notes	2027 Notes	700		(2)		698		700		(2)		698		2027 Notes	700		(2)		698		700		(2)		698
2028 Notes	2028 Notes	800		(5)		795		800		(5)		795		2028 Notes	800		(4)		796		800		(5)		795
2029 Notes	2029 Notes	547		(1)		546		550		(1)		549		2029 Notes	547		(1)		546		547		(1)		546
2044 Notes	2044 Notes	531		0		531		550		0		550		2044 Notes	531		0		531		531		0		531
EOIT Senior Notes		0		0		0		250		1		251
Total debt	Total debt	$	4,312	$	(8)	$	4,304	$	4,405	$	(7)	$	4,398	Total debt	$	4,192	$	(7)	$	4,185	$	4,228	$	(8)	$	4,220
Less: Short-term debt (2)	Less: Short-term debt (2)					334						155		Less: Short-term debt (2)					214						250
Less: Current portion of long-term debt (3)	Less: Current portion of long-term debt (3)					0						251		Less: Current portion of long-term debt (3)					800						0
Less: Unamortized debt expense (4)	Less: Unamortized debt expense (4)					20						23		Less: Unamortized debt expense (4)					19						19
Total long-term debt	Total long-term debt					$	3,950					$	3,969	Total long-term debt					$	3,152					$	3,951

____________________

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

(2)Short-term debt includes ~~$334~~$214 million and ~~$155~~$250 million of outstanding commercial paper as of ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019,~~2020, respectively.

(3)As of ~~December~~March 31, ~~2019,~~2021, Current portion of long-term debt included ~~$251~~$800 million outstanding balance of the ~~EOIT Senior Notes which were repaid in March 2020.~~2019 Term Loan Agreement.

(4)As of ~~September 30, 2020~~both March 31, 2021 and December 31, ~~2019,~~2020, there was an additional $3 million ~~and $4 million, respectively,~~ of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above.

Commercial Paper

The Partnership has a commercial paper program, pursuant to which the Partnership is authorized to issue up to $1.4 billion of commercial paper. The commercial paper program is supported by our Revolving Credit Facility, and outstanding commercial paper effectively reduces our borrowing capacity thereunder. There were ~~$334~~$214 million and ~~$155~~$250 million outstanding under our commercial paper program at ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019~~2020, respectively. As of ~~September 30, 2020,~~March 31, 2021, the weighted average interest rate for the outstanding commercial paper was ~~0.77%~~0.73%.

Revolving Credit Facility

The Partnership’s 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 2 times to extend the term of the Revolving Credit Facility, in each case, for an additional one-year term. As of ~~September 30, 2020,~~March 31, 2021, there were 0 principal advances, $3 million in letters of credit outstanding and our available borrowing capacity was approximately ~~$775~~$980 million under our Revolving Credit Facility.

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The Revolving Credit Facility provides that outstanding borrowings bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s designated credit ratings from S&P, Moody’s and Fitch Ratings. As of ~~September 30, 2020,~~March 31, 2021, the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was 1.50% based on the Partnership’s credit ratings. In addition, the Revolving Credit Facility requires the Partnership to pay a fee on unused commitments. The commitment fee is based on the Partnership’s credit ratings. As of ~~September 30, 2020,~~March 31, 2021, 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.

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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 ~~September 30, 2020,~~March 31, 2021, 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 2 times, to extend the maturity date for an additional one-year term. The 2019 Term Loan Agreement provides that outstanding borrowings bear interest at the eurodollar rate and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s credit ratings. The applicable margin shall equal, (1) in the case of interest rates determined by reference to the eurodollar rate, between 0.75% and 1.50% per annum and (2) in the case of interest rates determined by reference to the alternate base rate, between 0% and 0.50% per annum. As of ~~September 30, 2020,~~March 31, 2021, the applicable margin for LIBOR-based advances under the 2019 Term Loan Facility was 1.25% based on the Partnership’s credit ratings. As of ~~September 30, 2020,~~March 31, 2021, the weighted average interest rate of the 2019 Term Loan Agreement was ~~2.11%~~2.08%, including the impact of the associated interest rate derivatives designated as hedging instruments for accounting purposes.

Senior Notes

As of ~~September 30, 2020,~~March 31, 2021, the Partnership’s debt included the 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes and 2044 Notes, which had $8$7 million of unamortized discount and ~~$20~~$19 million of unamortized debt expense at ~~September 30, 2020,~~March 31, 2021, resulting in effective interest rates of 4.01%, 4.56%, 5.19%, ~~4.29%~~4.30% and ~~4.99%~~5.08%, respectively, during the ~~nine~~three months ended ~~September 30, 2020.~~March 31, 2021. In March 2020, the Partnership’s EOIT Senior Notes matured and were paid using proceeds from the Revolving Credit Facility.

During the nine months ended September 30, 2020, the Partnership repurchased $22 million aggregate principal amount of the 2029 Notes and 2044 Notes in open market transactions for approximately $17 million plus accrued interest, which resulted in a $5 million gain on extinguishment of debt. The gain is included in Other, net in the Condensed Consolidated Statements of Income.

As of ~~September 30, 2020,~~March 31, 2021, 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.

2221

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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.


		September 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020
		Gross Notional Volume					Gross Notional Volume
		Purchases	Sales	Purchases	Sales		Purchases	Sales	Purchases	Sales
Natural gas— TBtu (1)	Natural gas— TBtu (1)					Natural gas— TBtu (1)
Financial fixed futures/swaps	Financial fixed futures/swaps	4	25	10	19	Financial fixed futures/swaps	1	17	0	18
Financial basis futures/swaps	Financial basis futures/swaps	3	32	11	30	Financial basis futures/swaps	1	34	0	27
Financial swaptions (2)	Financial swaptions (2)	0	8	0	2	Financial swaptions (2)	0	5	0	7
Physical purchases/sales		0	1	0	6

Crude oil (for condensate)— MBbl (3)	Crude oil (for condensate)— MBbl (3)					Crude oil (for condensate)— MBbl (3)
Financial futures/swaps	Financial futures/swaps	0	540	0	990	Financial futures/swaps	0	420	0	465
Financial swaptions (2)	Financial swaptions (2)	0	90	0	225	Financial swaptions (2)	0	150	0	90
Natural gas liquids— MBbl (4)	Natural gas liquids— MBbl (4)					Natural gas liquids— MBbl (4)
Financial futures/swaps	Financial futures/swaps	1,395	1,410	2,490	2,415	Financial futures/swaps	435	1,155	855	1,210
Financial options	Financial options	0	75	0	0	Financial options	0	30	0	45

____________________

(1)As of ~~September 30, 2020, 91.9%~~March 31, 2021, 99.2% of the natural gas contracts had durations of one year or less and ~~8.1%~~0.8% had durations of more than one year and less than two years. As of December 31, ~~2019, 86.6%~~2020, 95.7% of the natural gas contracts had durations of one year or less and ~~13.4%~~4.3% 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 ~~September 30, 2020, 92.9%~~March 31, 2021, 89.5% of the crude oil (for condensate) contracts had durations of one year or less and ~~7.1%~~10.5% had durations of more than one year and less than two years. As of December 31, ~~2019, 72.8%~~2020, 100.0% 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.~~less.

(4)As of ~~September 30, 2020, 97.3%~~March 31, 2021, 97.2% of the natural gas liquids contracts had durations of one year or less and ~~2.7%~~2.8% had durations of more than one year and less than two years. As of December 31, ~~2019, 72.2%~~2020, 100.0% of the natural gas liquids contracts had durations of one year or ~~less and 27.8% had durations of more than one year and less than two years.~~less.

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.

September 30, 2020 December 31, 2019
Gross Notional Value
(In millions)
Interest rate swaps $ 300 $ 300


	March 31, 2021		December 31, 2020
	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.


			September 30, 2020				December 31, 2019						March 31, 2021				December 31, 2020
			Fair Value										Fair Value
Instrument	Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities		Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities

			(In millions)										(In millions)
Natural gas	Natural gas										Natural gas
Financial futures/swaps	Financial futures/swaps	Other Current	$	1	$	7	$	7	$	5	Financial futures/swaps	Other Current	$	1	$	3	$	2	$	2
Financial swaptions	Financial swaptions	Other Current	0		4		0		0		Financial swaptions	Other Current	1		2		1		2
Physical purchases/sales		Other Current	0		2		5		0
Financial futures/swaps		Other	0		0		0		1

Crude oil (for condensate)	Crude oil (for condensate)										Crude oil (for condensate)
Financial futures/swaps	Financial futures/swaps	Other Current	1		13		1		19		Financial futures/swaps	Other Current	0		10		1		13
Financial swaptions	Financial swaptions	Other Current	2		0		0		0		Financial swaptions	Other Current	0		1		0		0
Financial futures/swaps		Other	0		1		0		8

Natural gas liquids	Natural gas liquids										Natural gas liquids
Financial futures/swaps	Financial futures/swaps	Other Current	17		1		25		3		Financial futures/swaps	Other Current	9		6		15		3
Financial swaptions											Financial swaptions	Other Current	0		1		0		1

Financial futures/swaps		Other	1		0		11		2
Total gross commodity derivatives (1)	Total gross commodity derivatives (1)		$	22	$	28	$	49	$	38	Total gross commodity derivatives (1)		$	11	$	23	$	19	$	21

_____________________

(1)See Note 11 for a reconciliation of the Partnership’s commodity derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019.~~2020.

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.


			September 30, 2020				December 31, 2019						March 31, 2021				December 31, 2020
			Fair Value										Fair Value
Instrument	Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities		Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities

			(In millions)										(In millions)
Interest rate swaps(1)	Interest rate swaps(1)	Other Current	$	0	$	5	$	0	$	1	Interest rate swaps(1)	Other Current	$	0	$	5	$	0	$	6
Interest rate swaps		Other	0		2		0		2
Total gross interest rate derivatives (1)			$	0	$	7	$	0	$	3

_____________________

(1)All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019.~~2020.

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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										Amounts Recognized in Income
		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020

		(In millions)										(In millions)
Natural gas	Natural gas									Natural gas
Financial futures/swaps gains (losses)	Financial futures/swaps gains (losses)	$	(5)	$	2	$	(2)	$	10	Financial futures/swaps gains (losses)		$	(2)	$	4
Financial swaptions gains (losses)		(4)		0		(6)		0
Physical purchases/sales gains (losses)		(1)		1		0		1
Financial swaptions losses										Financial swaptions losses		0		(1)
Physical purchases/sales gains										Physical purchases/sales gains		0		1
Crude oil (for condensate)	Crude oil (for condensate)									Crude oil (for condensate)
Financial futures/swaps gains (losses)	Financial futures/swaps gains (losses)	0		(8)		12		(29)		Financial futures/swaps gains (losses)		(6)		19
Financial swaptions gains (losses)	Financial swaptions gains (losses)	0		0		2		0		Financial swaptions gains (losses)		(1)		4
Natural gas liquids	Natural gas liquids									Natural gas liquids
Financial futures/swaps gains (losses)		0		13		(1)		32
Financial futures/swaps losses										Financial futures/swaps losses		(5)		(7)
Total	Total	$	(10)	$	8	$	5	$	14	Total		$	(14)	$	20

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For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended ~~September 30,~~March 31, 2021 and 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 September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020

		(In millions)										(In millions)
Change in fair value of commodity derivatives	Change in fair value of commodity derivatives	$	(15)	$	(2)	$	(17)	$	(3)	Change in fair value of commodity derivatives		$	(10)	$	10
Realized gain on commodity derivatives		5		10		22		17
Realized gain (loss) on commodity derivatives										Realized gain (loss) on commodity derivatives		(4)		10
Gain (loss) on commodity derivative activity	Gain (loss) on commodity derivative activity	$	(10)	$	8	$	5	$	14	Gain (loss) on commodity derivative activity		$	(14)	$	20

The following table presents the effect of derivative instruments that were designated as hedging instruments on the Partnership’s Condensed Consolidated Statements of Income.

Amounts Recognized in Income
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions)
Interest rate swaps losses $ (2) $ 0 $ (3) $ 0
Total $ (2) $ 0 $ (3) $ 0


		Amounts Recognized in Income
	Three Months Ended March 31,
		2021		2020

		(In millions)
Interest rate swaps losses		$	(1)	$	0

Interest rate derivatives designated as hedges are recognized in income once settled. Settlement amounts recognized in income for the periods ended ~~September 30,~~March 31, 2021 and 2020 ~~and 2019~~ are reported in Interest expense.

Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody’s or S&P were to lower the Partnership’s senior unsecured debt rating to a below investment grade rating, the Partnership could be required to provide additional credit assurances to third parties, which could include letters of credit or cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position. As of ~~September 30, 2020,~~March 31, 2021, under these obligations, the Partnership ~~has~~had posted 0 cash collateral related to natural gas swaps and swaptions, crude oil swaps and swaptions and NGL swaps and $3$1 million of additional

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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 ~~and nine~~ months ended ~~September 30, 2020,~~March 31, 2021, there were no transfers between levels. As of ~~September 30, 2020,~~March 31, 2021, 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.

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The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments.


		September 30, 2020				December 31, 2019					March 31, 2021				December 31, 2020
		Carrying Amount		Fair Value		Carrying Amount		Fair Value			Carrying Amount		Fair Value		Carrying Amount		Fair Value

		(In millions)									(In millions)
Debt	Debt									Debt
Revolving Credit Facility (Level 2) (1)	Revolving Credit Facility (Level 2) (1)	$	0	$	0	$	0	$	0	Revolving Credit Facility (Level 2) (1)	$	0	$	0	$	0	$	0
2019 Term Loan Agreement (Level 2)	2019 Term Loan Agreement (Level 2)	800		800		800		800		2019 Term Loan Agreement (Level 2)	800		800		800		800

2024 Notes (Level 2)	2024 Notes (Level 2)	600		591		600		614		2024 Notes (Level 2)	600		639		600		612
2027 Notes (Level 2)	2027 Notes (Level 2)	698		674		698		698		2027 Notes (Level 2)	698		758		698		709
2028 Notes (Level 2)	2028 Notes (Level 2)	795		784		795		811		2028 Notes (Level 2)	796		884		795		817
2029 Notes (Level 2)	2029 Notes (Level 2)	546		505		549		526		2029 Notes (Level 2)	546		568		546		544
2044 Notes (Level 2)	2044 Notes (Level 2)	531		448		550		506		2044 Notes (Level 2)	531		527		531		499
EOIT Senior Notes (Level 2)		0		0		251		252

____________________

(1) Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. ~~$334~~$214 million and ~~$155~~$250 million of commercial paper was outstanding as of ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019,~~2020, 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~~2044 Notes is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy.

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

Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment). As of ~~September 30, 2020,~~March 31, 2021, 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 and Note 8.~~liabilities.

Based upon review of forecast undiscounted cash flows as of ~~September 30, 2020,~~March 31, 2021, all of the asset groups were considered ~~recoverable, other than those discussed in Note 7.~~recoverable. Based upon review for other than temporary declines in fair value, the investment in equity method affiliate was considered ~~recoverable, other than as discussed in Note 8.~~recoverable. Future price declines, throughput declines, contracted capacity declines, cost increases, regulatory or political environment changes and other changes in market conditions, including the oversupply of crude oil, NGLs and natural gas as well as the ongoing COVID-19 pandemic and the economic effects of the pandemic, could reduce forecast undiscounted cash flows for the asset groups and result in other than temporary declines in the fair value of the investment in equity method affiliate.

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Contracts with Master Netting Arrangements

As of ~~September 30, 2020,~~March 31, 2021, 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.


September 30, 2020		Commodity Contracts				Gas Imbalances (1)
March 31, 2021										March 31, 2021	Commodity Contracts				Gas Imbalances (1)
		Assets		Liabilities		Assets (2)		Liabilities (3)			Assets		Liabilities		Assets (2)		Liabilities (3)

		(In millions)									(In millions)
Quoted market prices in active market for identical assets (Level 1)	Quoted market prices in active market for identical assets (Level 1)	$	1	$	22	$	0	$	0	Quoted market prices in active market for identical assets (Level 1)	$	1	$	10	$	0	$	0
Significant other observable inputs (Level 2)	Significant other observable inputs (Level 2)	21		6		16		11		Significant other observable inputs (Level 2)	10		13		30		10

Total fair value	Total fair value	22		28		16		11		Total fair value	11		23		30		10
Netting adjustments	Netting adjustments	(22)		(22)		0		0		Netting adjustments	(11)		(11)		0		0
Total	Total	$	0	$	6	$	16	$	11	Total	$	0	$	12	$	30	$	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 $ 0 $ 0
Significant other observable inputs (Level 2) 44 7 14 11
Total fair value 49 38 14 11
Netting adjustments (37) (37) 0 0
Total $ 12 $ 1 $ 14 $ 11

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December 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)	$	2	$	14	$	0	$	0
Significant other observable inputs (Level 2)	17		7		23		16

Total fair value	19		21		23		16
Netting adjustments	(19)		(19)		0		0
Total	$	0	$	2	$	23	$	16

______________________

(1)The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. There were no netting adjustments as of ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019.~~2020.

(2)Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of ~~$22~~$19 million and ~~$21~~$19 million at ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019,~~2020, 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 $3 million and $8$3 million at ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019,~~2020, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created, and which are not subject to revaluation at fair market value.

(12) Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:

Nine Months Ended September 30,
2020 2019
(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest $ 129 $ 131
Income taxes, net of refunds 1 1
Non-cash transactions:
Accounts payable related to capital expenditures 9 26
Lease liabilities related to (derecognition) recognition of right-of-use assets (5) 42
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:

September 30,
2020 2019
(In millions)
Cash and cash equivalents $ 18 $ 12
Restricted cash 0 1
Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows $ 18 $ 13


	Three Months Ended March 31,
	2021		2020

	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	32	$	43
Income taxes, net of refunds	(2)		0
Non-cash transactions:
Accounts payable related to capital expenditures	7		8
Lease liabilities related to derecognition of right-of-use assets	0		(4)
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)	0		(3)

(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.

EGT provides natural gas transportation and storage services to CenterPoint Energy’s LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas under a combination of contracts that include the following types of services: firm transportation, firm transportation with seasonal demand, firm storage, no-notice transportation with storage and maximum rate firm transportation. The firm transportation, firm transportation with seasonal demand, firm storage and no-notice transportation with storage contracts were extended and have terms running through March 31, 2030. The maximum rate firm transportation contracts were also extended and have terms running through March 31, 2024.

The Partnership’s revenues from affiliated companies accounted for 6%7% and 8% of total revenues during ~~both~~ the ~~nine~~three months ended ~~September 30,~~March 31, 2021 and 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 September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020

		(In millions)										(In millions)
Gas transportation and storage service revenues — CenterPoint Energy	Gas transportation and storage service revenues — CenterPoint Energy	$	17	$	22	$	76	$	78	Gas transportation and storage service revenues — CenterPoint Energy		$	27	$	37
Natural gas product sales — CenterPoint Energy		0		3		1		7

Gas transportation and storage service revenues — OGE Energy	Gas transportation and storage service revenues — OGE Energy	9		9		28		35		Gas transportation and storage service revenues — OGE Energy		10		9
Natural gas product sales — OGE Energy	Natural gas product sales — OGE Energy	4		4		9		5		Natural gas product sales — OGE Energy		31		5
Total revenues — affiliated companies	Total revenues — affiliated companies	$	30	$	38	$	114	$	125	Total revenues — affiliated companies		$	68	$	51

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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 September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020

		(In millions)										(In millions)
Cost of natural gas purchases — CenterPoint Energy	Cost of natural gas purchases — CenterPoint Energy	$	0	$	0	$	1	$	0	Cost of natural gas purchases — CenterPoint Energy		$	0	$	1
Cost of natural gas purchases — OGE Energy	Cost of natural gas purchases — OGE Energy	6		12		20		25		Cost of natural gas purchases — OGE Energy		31		8
Total cost of natural gas purchases — affiliated companies	Total cost of natural gas purchases — affiliated companies	$	6	$	12	$	21	$	25	Total cost of natural gas purchases — affiliated companies		$	31	$	9

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

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Board of Enable GP. The Partnership reimburses CenterPoint Energy and OGE Energy for these services up to annual caps, which for ~~2020~~2021 are ~~0 and~~both less than $1 ~~million, respectively.~~million.

As of ~~September 30, 2020~~March 31, 2021, 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 September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions)
Seconded Employee Costs — OGE Energy $ 5 $ 4 $ 13 $ 15


	Three Months Ended March 31,
		2021		2020

		(In millions)


Seconded Employee Costs — OGE Energy		$	4	$	3

(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 deliveries to the Godley Plant in Johnson County, Texas. As of ~~September 30, 2020,~~March 31, 2021, the Partnership estimates the remaining associated minimum volume commitment fee to be ~~$175~~$164 million. Minimum volume commitment fees are expected to be $3$15 million for the remainder of ~~2020,~~2021, $23 million per year from ~~2021~~2022 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 liquefied natural gas 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 Partnership filed applications with FERC to obtain authorization to construct and operate the pipeline on February 28, 2020. FERC issued the environmental assessment on October 29, 2020. ~~Under the precedent agreement, the~~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~~$540 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

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Haynesville, Marcellus, Utica and Barnett shales and the Mid-Continent region. The project is expected to be placed into service in late 2022.

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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 September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020

		(In millions)										(In millions)
Performance units	Performance units	$	1	$	3	$	5	$	8	Performance units		$	2	$	2

Phantom units	Phantom units	2		1		5		5		Phantom units		2		2
Total compensation expense	Total compensation expense	$	3	$	4	$	10	$	13	Total compensation expense		$	4	$	4

The following table presents the assumptions related to the performance ~~share~~ units granted in ~~2020.~~2021.

~~2020~~2021

Number of units granted

~~933,738~~1,453,897

Fair value of units granted

$ ~~7.00~~

10.26

Expected distribution yield

~~12.27~~12.90

Expected price volatility

~~27.70~~100.00

Risk-free interest rate

~~0.85~~0.27

Expected life of units (in years)

The following table presents the number of phantom units granted and the grant date fair value related to the phantom units granted in ~~2020.~~2021.

~~2020~~2021

Phantom Units granted

~~967,095~~1,356,672

Fair value of phantom units granted

$~~2.67~~5.41 - ~~$10.13~~$6.87

Units Outstanding

A summary of the activity for the Partnership’s performance units and phantom units applicable to the Partnership’s employees at ~~September 30, 2020~~March 31, 2021 and changes during ~~2020~~2021 are shown in the following table.


		Performance Units				Phantom Units					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				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)									(In millions, except unit data)
Units outstanding at December 31, 2019		1,393,329		$	19.04		1,392,560		$	14.65
Units outstanding at December 31, 2020												Units outstanding at December 31, 2020	1,765,508		$	13.10	1,790,845		$	10.29
Granted (1)	Granted (1)	933,738		7.00			967,095		6.51			Granted (1)	1,453,897		10.26		1,356,672		6.86

Vested (2)	Vested (2)	(387,174)		19.23			(378,192)		15.99			Vested (2)	(389,817)		17.70		(461,824)		13.11
Forfeited	Forfeited	(154,534)		14.39			(189,397)		10.47			Forfeited	(32,625)		10.00		(94,669)		8.70
Units outstanding at September 30, 2020		1,785,359		$	13.11		1,792,066		$	10.42
Aggregate intrinsic value of units outstanding at September 30, 2020		$	7				$	7
Units outstanding at March 31, 2021												Units outstanding at March 31, 2021	2,796,963		$	11.02	2,591,024		$	8.05
Aggregate intrinsic value of units outstanding at March 31, 2021												Aggregate intrinsic value of units outstanding at March 31, 2021	$	18			$	17

_____________________

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

(2)Performance units vested as of ~~September 30, 2020~~March 31, 2021 include ~~376,292~~389,817 units from the ~~2017~~2018 annual grant, which were approved by the Board of Directors in ~~2017~~2018 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~~2018 through December 31, ~~2019,~~2020, no performance units vested.

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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.


		September 30, 2020				March 31, 2021
		Unrecognized Compensation Cost (In millions)		Weighted Average Period for Recognition (In years)		Unrecognized Compensation Cost (In millions)		Weighted Average Period for Recognition (In years)
Performance Units	Performance Units	$	11	1.68	Performance Units	$	21	2.25

Phantom Units	Phantom Units	8		1.53	Phantom Units	14		2.07
Total	Total	$	19		Total	$	35

As of ~~September 30, 2020,~~March 31, 2021, there were ~~5,294,366~~3,105,706 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~~2020 Notes to 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 2 reportable segments: (i) gathering and processing ~~which~~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 ~~(ii)~~crude oil, condensate and produced water gathering services to our producer and refiner customers. The transportation and storage ~~which~~segment provides interstate and intrastate natural gas pipeline transportation and storage ~~service~~services 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 September 30, 2020 Gathering and
Processing
Transportation (1)
and Storage
Eliminations Total
(In millions)
Product sales $ 271 $ 79 $ (70) $ 280
Service revenues 192 126 (2) 316
Total Revenues 463 205 (72) 596
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 244 78 (72) 250
Operation and maintenance, General and administrative 77 47 0 124
Depreciation and amortization 75 30 0 105
Taxes other than income tax 10 7 0 17
Operating income $ 57 $ 43 $ 0 $ 100
Total Assets $ 9,525 $ 5,524 $ (3,274) $ 11,775
Capital expenditures $ 21 $ 29 $ 0 $ 50
Three Months Ended September 30, 2019 Gathering and
Processing
Transportation (1)
and Storage
Eliminations Total
(In millions)
Product sales $ 294 $ 100 $ (74) $ 320
Service revenues 248 134 (3) 379
Total Revenues 542 234 (77) 699
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 238 102 (77) 263
Operation and maintenance, General and administrative 79 57 0 136
Depreciation and amortization 77 31 0 108
Taxes other than income tax 10 7 0 17
Operating income $ 138 $ 37 $ 0 $ 175
Total assets as of December 31, 2019 $ 9,739 $ 5,886 $ (3,359) $ 12,266
Capital expenditures $ 70 $ 31 $ 0 $ 101

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Nine Months Ended September 30, 2020		Gathering and Processing		Transportation (1) and Storage		Eliminations		Total
Three Months Ended March 31, 2021										Three Months Ended March 31, 2021	Gathering and Processing		Transportation (1) and Storage		Eliminations		Total

											(In millions)
Product sales										Product sales	$	428	$	332	$	(133)	$	627
Service revenues										Service revenues	196		150		(3)		343
Total Revenues										Total Revenues	624		482		(136)		970
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)										Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	398		257		(136)		519
Operation and maintenance, General and administrative										Operation and maintenance, General and administrative	79		42		0		121
Depreciation and amortization										Depreciation and amortization	74		32		0		106

Taxes other than income tax										Taxes other than income tax	11		7		0		18
Operating income										Operating income	$	62	$	144	$	0	$	206
Total Assets										Total Assets	$	10,780	$	5,789	$	(4,805)	$	11,764
Capital expenditures										Capital expenditures	$	21	$	59	$	0	$	80

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

		(In millions)									(In millions)
Product sales	Product sales	$	739	$	213	$	(188)	$	764	Product sales	$	275	$	75	$	(62)	$	288
Service revenues	Service revenues	592		409		(6)		995		Service revenues	202		159		(1)		360
Total Revenues	Total Revenues	1,331		622		(194)		1,759		Total Revenues	477		234		(63)		648
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	631		215		(193)		653		Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	211		78		(63)		226
Operation and maintenance, General and administrative	Operation and maintenance, General and administrative	250		137		(1)		386		Operation and maintenance, General and administrative	81		45		0		126
Depreciation and amortization	Depreciation and amortization	223		91		0		314		Depreciation and amortization	74		30		0		104
Impairments of property, plant and equipment and goodwill	Impairments of property, plant and equipment and goodwill	28		0		0		28		Impairments of property, plant and equipment and goodwill	28		0		0		28
Taxes other than income tax	Taxes other than income tax	32		20		0		52		Taxes other than income tax	11		7		0		18
Operating income	Operating income	$	167	$	159	$	0	$	326	Operating income	$	72	$	74	$	0	$	146
Total Assets		$	9,525	$	5,524	$	(3,274)	$	11,775
Total assets as of December 31, 2020										Total assets as of December 31, 2020	$	10,830	$	5,729	$	(4,830)	$	11,729
Capital expenditures	Capital expenditures	$	79	$	73	$	0	$	152	Capital expenditures	$	34	$	20	$	0	$	54

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

		(In millions)
Product sales		$	1,096	$	381	$	(321)	$	1,156
Service revenues		663		421		(11)		1,073
Total Revenues		1,759		802		(332)		2,229
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)		895		394		(331)		958
Operation and maintenance, General and administrative		238		152		(1)		389
Depreciation and amortization		229		94		0		323
Taxes other than income tax		31		21		0		52
Operating income		$	366	$	141	$	0	$	507
Total assets as of December 31, 2019		$	9,739	$	5,886	$	(3,359)	$	12,266
Capital expenditures		$	267	$	86	$	0	$	353

_____________________

(1)See Note 8 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three ~~and nine~~ months ended ~~September 30, 2020~~March 31, 2021 and ~~2019.~~2020.

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,~~2020, 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 COVID-19 pandemic and the economic effects of the pandemic. Our actual results could differ materially from those discussed in these forward-looking statements. Please read “Forward-Looking Statements.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

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Overview

Enable Midstream Partners, LP ~~is a Delaware limited partnership formed in May 2013 to own, operate~~owns, operates and ~~develop~~develops 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~~NYSE 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~~Liquidity and Capital Resources

The Partnership’s principal liquidity requirements are to finance its operations, fund capital expenditures and acquisitions, make cash distributions and satisfy any indebtedness obligations. We expect that our liquidity and capital resource needs will be met by our sources of liquidity, which as of March 31, 2021, included cash on hand, operating cash flow, proceeds from commercial paper issuances, borrowings under our revolving credit facility, debt issuances and the issuance of equity. For more information on our commercial paper program, our revolving credit agreement, our other outstanding debt agreements and preferred equity, please see Note 6 “Partners’ Equity” and Note 9 “Debt” in the Notes to the Unaudited Condensed Consolidated Financial Statements under Item 1. “Financial Statements.”

Cash on hand and operating cash flow can be subject to fluctuations due to trends and uncertainties that are beyond our control. Likewise, our ability to issue commercial paper, equity and debt and our ability to obtain credit facilities on favorable terms may be impacted by a variety of market factors as well as fluctuations in our results of operations. For more information on conditions impacting our liquidity and capital resources, see “Results of Operations—Trends and Uncertainties Affecting Results of Operations.” For further discussion of risks related to our liquidity and capital resources, see Item 1A. “Risk Factors” in our Annual Report.

Working Capital

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March 31, 2021, we had a working capital deficit of $885 million. The deficit is primarily due to the classification of $800 million of the 2019 Term Loan Agreement as Current portion of long-term debt as of March 31, 2021 as well as $214 million of commercial paper outstanding as of March 31, 2021.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,
	2021		2020

	(In millions)
Net cash provided by operating activities	$	223	$	200
Net cash used in investing activities	(75)		(48)
Net cash used in financing activities	(119)		(152)

Operating Activities

The increase of $23 million or 12%, in net cash provided by operating activities for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020 was primarily driven by an increase in net income of $60 million, partially offset by a decrease in adjustments for non-cash items of $26 million and a decrease of $11 million in the timing of cash receipts and disbursements and changes in other working capital assets and liabilities.

Investing Activities

The increase of $27 million, or 56%, in net cash used in investing activities for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020 was primarily due to higher capital expenditures of $26 million, a decrease in other investing cash flows of $1 million and a decrease in return of investment in equity method affiliate of $1 million, partially offset by an increase in proceeds from sale of assets of $1 million.

Financing Activities

Net cash used in financing activities decreased $33 million, or 22%, for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020. Our primary financing activities consist of the following:


	Three Months Ended March 31,
	2021		2020

	(In millions)
Decrease in short-term debt	$	(36)	$	(45)


Repayment of EOIT Senior Notes	—		(250)


Net proceeds from Revolving Credit Facility	—		300

Distributions	(82)		(156)
Cash paid for employee equity-based compensation	(1)		(1)

Distributions

On April 26, 2021, 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, 2021. The distributions will be paid May 25, 2021 to unitholders of record as of the close of business on May 13, 2021. Additionally, the Board of Directors declared a quarterly cash distribution of $0.5873 on the Partnership’s outstanding Series A Preferred Units. The distributions will be paid May 14, 2021 to unitholders of record as of the close of business on April 26, 2021.

Trends Affecting Liquidity and Capital Resources

Borrowing Capacity

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day of each fiscal quarter of less than or equal to 5.00 to 1.00. As of March 31, 2021, our available borrowing capacity under our Revolving Credit Facility was approximately $980 million due to this financial covenant, prior to invoking any amounts related to Qualified Project EBITDA Adjustments (as defined in the Revolving Credit Facility). However, we believe that we will have sufficient cash flow and borrowing capacity to fully fund our business.

Results of Operations

Trends and Uncertainties Affecting Results of Operations

Energy Transfer Merger

On February 16, 2021, we entered into a definitive Merger Agreement with Energy Transfer, pursuant to which, among other things, all outstanding common units of the Partnership will be acquired by Energy Transfer in an all-equity transaction, including the assumption of debt and other liabilities, subject to the conditions of the Merger Agreement.

Under the terms of the Merger Agreement, our common unitholders will receive 0.8595 of one common unit representing limited partner interests in Energy Transfer for each common unit of the Partnership. In addition, each issued and outstanding Series A Preferred Unit of the Partnership will be exchanged for 0.0265 of an Energy Transfer Series G preferred unit, and Energy Transfer will make a $10 million cash payment to the owners of the Partnership’s general partner for the limited liability company interests in Enable GP. The transaction was approved by the boards of directors of the general partners of both partnerships and the Conflicts Committee of our Board of Directors. The transaction is subject to the receipt of the required approvals from the holders of a majority of our common units, regulatory approvals, and other customary closing conditions.

Pursuant to a consent statement/prospectus dated April 8, 2021, which was included as part of a Registration Statement on Form S-4 filed by Energy Transfer, the Partnership solicited written consents from its common unitholders to approve the Merger Agreement and, on a non-binding, advisory basis, the compensation that will or may become payable to the Partnership’s named executive officers in connection with the transactions contemplated by the Merger Agreement. Pursuant to previously disclosed support agreements, CenterPoint Energy and OGE Energy, who collectively own approximately 79.2% of the Partnership’s common units, delivered written consents approving the Merger Agreement and, on a non-binding, advisory basis, the transaction-related compensation proposal. While the consents of CenterPoint Energy and OGE Energy are sufficient to approve the transaction, the Partnership is requesting that all of its common unitholders approve the Merger and other proposals outlined in the consent statement/prospectus by executing and returning the written consents furnished therewith.

The Merger is anticipated to close in mid-2021, subject to the satisfaction of customary closing conditions, including Hart-Scott-Rodino clearance. We cannot provide any assurance that the combination will be completed on the terms or timeline currently contemplated, or at all. The above is a summary of the material terms of the Merger and is qualified in its entirety by reference to the Registration Statement on Form S-4 (which became effective on April 7, 2021) filed by Energy Transfer.

COVID-19 Pandemic

~~In March 2020,~~Throughout 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 took actions to limit the spread of COVID-19 through travel restrictions and stay-at-home orders, which 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. Following the lifting of travel restrictions and stay-at-home orders, COVID-19 cases in the United States have increased, creating additional uncertainty regarding the timing, pace and extent of an economic recovery in the United States.

~~Our~~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. ~~Beginning in March 2020,~~In compliance with Center for Disease Control guidance, we ~~took action~~implemented strategies 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 was not possible, we implemented strategies to reduce the likelihood of spreading the disease. In compliance with Center for Disease Control guidance, these strategies include requiring sick employees to stay home, conducting dailyincluding virtual ~~health checks, implementing policies and practices for~~symptom screening, social distancing, ~~and~~ wearing ~~cloth face coverings, educating employees about steps they can take to protect themselves at work and at home, performing enhanced cleaning and disinfecting,~~masks, limiting non-essential travel, and,

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~~minimizing meetings and gatherings. For contractors, vendors, and suppliers who are necessary to support our operations on-site,~~ where possible, utilizing remote working. In April 2021, we ~~have required them to implement similar policies and practices.~~

~~In June 2020, we~~ began to return those employees to the workplace that have beem working remotely. As part of our return to work protocols, we implemented the same strategies described above to reduce the likelihood of spreading the disease. In addition, we have limited the number of employees in the workplace in order to maintain strict social distancing practices and made accommodations for employees at higher risk of severe illness. As infection and hospitalization rates have increased in areas where we operate, we have temporarily halted returning additional employees to the ~~office.~~workplace who had been working remotely. We ~~intend to increase the number of employees in the workplace as conditions warrant, and we~~ will continue to monitor for the ~~emergence or~~ resurgence of COVID-19 in our workplaces and in the communities where our employees are ~~located.~~located and adjust our strategies accordingly.

~~Market Dynamics~~Commodity Price Environment

~~Prior~~Our business is impacted by commodity prices, which have continued to experience significant volatility. Commodity prices impact the ~~COVID-19 pandemic, the price~~drilling and production of natural gas ~~NGLs~~ and crude oil ~~had begun to decline due to oversupply. The price of, and global demand for, these commodities have continued to decline significantly as a result of~~in the ~~ongoing economic effects of the COVID-19 pandemic~~areas served by our systems, and the ~~significant governmental measures being implemented to control~~volumes on our systems are impacted by the ~~spread~~amount of ~~the virus. In addition, the dispute~~drilling and production in the ~~first quarter~~areas we serve. Both our gathering and processing segment and our transportation and storage segment can be affected by drilling and production. For more information regarding the impact of ~~2020 over crude oil~~commodity prices, drilling and production ~~levels between Russia and members of OPEC led by Saudi Arabia exacerbated~~on the ~~decline~~volumes on our systems as well as our exposure to commodity prices under our processing arrangements, see Item 1A. “Risk Factors—Risks Related to Our Business” in the prices 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 prices of NGLs and crude oil have remained depressed relative to pre-pandemic levels.our Annual Report.

~~Financial markets~~

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We have ~~recently experienced extreme volatility as a result~~attempted to mitigate the impact of ~~the economic uncertainty arising out of the COVID-19 pandemic. Market volatility, together with deteriorating credit, liquidity concerns, decreasing production,~~commodity prices on our business by entering into hedges, focusing on contracting fee-based business and ~~increasing inventories, are conditions that are associated with a general economic downturn. Producers have announced and implemented plans~~converting existing commodity-based contracts to ~~reduce production and decrease the drilling and completion of wells in response to these conditions. These plans include reductions in the exploration, development and production activity across~~fee-based contracts. For additional information regarding our ~~areas of operation. As a result, the effects of the COVID-19 pandemic have and may continue to negatively impact the demand for midstream services.~~

~~The effects of the COVID-19 pandemic, which have exacerbated~~ commodity price ~~declines resulting from oversupply by decreasing demand, may also increase counterparty credit risk. Some customers may encounter severe financial problems that could limit~~risk, see Item 7A. “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk” in our ability to collect amounts owed to us or to enforce performance of other obligations under contractual arrangements. During the nine months ended September 30, 2020, five of our producer customers filed for reorganization under Chapter 11 of the Bankruptcy Code. We do not anticipate that these bankruptcies will result in a significant impact on our results of operations.Annual Report.

During the three ~~and nine~~ months ended ~~September 30, 2020~~March 31, 2021 as compared to the three ~~and nine~~ months ended ~~September 30, 2019,~~March 31, 2020, our revenues and gross margin increased. These increases resulted primarily from the impact of the February 2021 Winter Storm Uri on the areas in which we operate. The winter storm temporarily increased the price of natural gas, which increased our proceeds from product sales. The winter storm also temporarily increased the demand for natural gas for heating, which resulted in imbalance penalties for customers on our gathering and processing and transportation and storage systems for customers who failed to balance actual receipts and deliveries at nominated and confirmed levels. The results of our most recent period may not be indicative of our future results because of the temporary effects of the winter storm. For more information on our results, see “—Financial Results” below.

During the three months ended March 31, 2021 as compared to the three months ended March 31, 2020, our natural gas gathered volumes, processed volumes, transported volumes, ~~revenues~~ and ~~gross margin~~crude oil and condensate gathered volumes decreased. These decreases resulted primarily from reductions in the production of natural gas, ~~combined with reductions in the demand for natural gas,~~ NGLs and crude oil. The reductions in supply ~~and demand for~~of these commodities, and the resulting decrease in demand for midstream services, were caused by the effects of preexisting oversupply conditions and exacerbated by the decrease in economic activity due to the COVID-19 pandemic. ~~While we believe that the demand for midstream services will remain below 2019 levels for as long as these conditions persist, the~~The results for our most recent period may not be indicative of our future results because of the continuing uncertainty surrounding future levels of production of natural gas, NGLs and crude oil, and the demand for midstream services to move that production to ~~markets, as well as uncertainty regarding the creditworthiness of our customers.~~markets. For more information on our results, see ~~“Results of Operations”~~“—Financial Results” below.

We continue to actively respond 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 forecast expansion capital expenditures for 2020, which limits our forecast 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 forecast 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.~~

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

As part of the reduction in our operations and maintenance and general and administrative expenses, in the fourth quarter of 2019, we began a review of our organizational structure and staffing levels to maximize efficiency and flexibility. As a result of this review, we have reduced our positions by 165 through July 31, 2020. Of these 165 reductions, 134 were made between May 1, 2020 through July 31, 2020. We believe that these reductions will improve our long-term cost structure.

Our Revolving Credit Facility and our 2019 Term Loan Agreement each contain a financial covenant limiting our ratio of consolidated funded indebtedness to consolidated earnings before interest, taxes, depreciation and amortization as of the last day of each fiscal quarter of less than or equal to 5.00 to 1.00. Our financial results, which have been impacted by the effects of preexisting oversupply conditions and exacerbated by the decrease in economic activity due to the COVID-19 pandemic, have lowered our aggregate borrowing capacity under our Revolving Credit Facility. As of September 30, 2020, our available borrowing capacity under our Revolving Credit Facility was approximately $775 million. Considering these financial covenants, we believe that we will have sufficient cash flow and borrowing capacity to fully fund our business and expect to continue to proactively take steps to maintain sufficient liquidity and capital resources for our business.

We were not eligible and did not receive any assistance under the Paycheck Protection Program. Under the CARES Act, we elected to defer employer payroll taxes incurred in 2020, into 2021 and 2022. Additionally, we elected to apply the net operating loss carryback provisions of the CARES Act to Enable Midstream Services, LLC. Applying these provisions will not significantly impact our short-term or long-term liquidity needs.

We cannot currently predict the duration and extent of the impact of the COVID-19 pandemic on the financial and commodity markets, or the duration and extent of the impact global oversupply on the production of natural gas, NGLs and crude oil or the demand for midstream services. Depending upon the duration and extent of reduced economic activity from the COVID-19 pandemic and attendant reduction in demand for hydrocarbons, as well as the global oversupply of natural gas, NGLs and crude oil and the attendant reduction in producer activities and energy commodity prices, we may experience asset impairments in future reporting periods.

~~Commercial Update~~

~~Sale of Interest in Bistineau Storage Facility~~

On April 1, 2020, the Partnership closed on the sale of its undivided 1/12th interest in the Bistineau Storage Facility in Louisiana for approximately $19 million. We did not recognize a gain or loss on this transaction.

~~Loss on Retirement of Ark-La-Tex Gathering System~~

In April 2020, the Partnership sustained damage to an approximately 100-mile gas gathering system in the Ark-La-Tex Basin of our gathering and processing segment. We have ceased operation of this system and are in process of retiring it. We recognized a loss on retirement of approximately $20 million during the second quarter of 2020.Recent Developments

Dakota Access Pipeline

On July 6, 2020, the federal district court for the District of Columbia (the “District Court”) issued an order ~~requiring~~vacating an easement, that was issued by the U.S. Corps of Engineers and which allowed Dakota Access Pipeline to ~~be shut down and emptied of oil by August 5, 2020,~~cross the Missouri River, pending the completion of an environmental impact analysis for the pipeline. ~~The U.S. Court of Appeals for~~Although the pipeline currently continues to operate, the District ~~of Columbia Circuit stayed~~Court is considering whether to order the ~~order requiring the~~pipeline shut down ~~in order to consider~~during the ~~pipeline’s emergency motion for stay.~~pendency of the environmental review. Substantially all of the crude oil gathered by our Williston Basin crude oil systems is delivered indirectly for transport to Dakota Access Pipeline. A shutdown of Dakota Access Pipeline could occur if the Corps does not grant an easement following the completion of the environmental impact statement. Although the crude oil gathered by our Williston Basin crude oil systems may also be delivered for transport to other pipelines, such as BakkenLink Pipeline and ~~Bridger~~Enbridge North Dakota Pipeline, a shutdown of the Dakota Access Pipeline, or any other significant pipeline providing transportation services from the Williston Basin, would likely result in the ~~shut in~~shut-in of wells connected to our Williston Basin crude oil systems if our customer is unable to obtain sufficient capacity on those pipelines at an effective cost. On August 5, 2020, the DC Circuit: (1) stayed the injunction issued by the district court, finding that the district court failed to make the findings necessary for injunctive relief, but (2) denied the motion to stay the district court’s order vacating the easement authorizing Dakota Access Pipeline to cross the Missouri River at Lake Oahe. Oral argument has been set for November 4, 2020 in Dakota Access Pipeline’s appeal of the district court’s order requiring the U.S. Army Corps of Engineers to conduct an environmental impact statement prior to granting an easement authorizing Dakota Access Pipeline to cross the Missouri River at Lake Oahe. Under the briefing schedule approved by the DC Circuit, the earliest a ruling could be expected is late December 2020. Although the threatened shutdown of Dakota Access Pipeline is no longer imminent, a shutdown could occur if Dakota Access Pipeline loses its appeal and the U.S. Army Corps of Engineers either does not grant Dakota Access Pipeline an easement following the completion of the

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~~environmental impact statement or determines that, under the U.S. Army Corps of Engineers regulations, Dakota Access Pipeline must be shut down while the environmental impact statement is prepared.~~ We are unable to predict whether any such pipeline will be ~~shutdown,~~shut down, the duration of any such shutdown, or the extent of the resulting impact on the operations of our Williston Basin crude oil and produced water gathering systems.

~~Impairment of equity method affiliate investment~~

As of September 30, 2020, the Partnership estimated the fair value of its equity method affiliate investment was below the carrying value and concluded the decline in value was other than temporary due to the expiration of a transportation contract and the current status of renewal negotiations. As a result, the Partnership recorded a $225 million impairment on its equity method affiliate investment for the three and nine months ended September 30, 2020, which is included in Equity in earnings (losses) of equity method affiliate, net in the Partnership’s Condensed Consolidated Statements of Income.

~~Regulatory Update~~

~~MRT Rate Case~~

On March 26, 2020, FERC issued an order approving settlements filed in the MRT rate cases filed in June 2018 and October 2019. The settlements 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. In May 2020, $21 million previously held in reserve was refunded to customers, which was inclusive of interest.

~~PHMSA Update~~

On July 1, 2020, the Safety of Hazardous Liquid Pipelines rule and the Safety of Gas Transmission Pipelines rule became effective. We do not anticipate that we will incur material compliance costs in connection with these rules in 2020, and we estimate that we will incur an average of $10 million per year in additional costs to comply with these rules beginning in 2022.

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 pending pipeline safety regulations, and any other future pipeline safety laws and regulations, which could have a material impact on our costs of and revenues from operations.

Five Nations Reservations

On July 9, 2020, the U.S. Supreme Court ruled that the Muscogee (Creek) Nation reservation in Eastern Oklahoma has not been disestablished. Prior to the court’s ruling, the prevailing view was that the Muscogee (Creek) Nation, Chickasaw Nation, Cherokee Nation, Choctaw Nation and Seminole Nation reservations within Oklahoma had been disestablished prior to statehood in 1907. Although the court’s ruling indicates that it is limited to criminal law as applied within the Muscogee (Creek) Nation reservation, the ruling has significant potential implications for civil law within the Muscogee (Creek) Nation reservation, as well as other reservations in Oklahoma that may similarly be found to not have been disestablished. A significant amount of our gathering and processing and transportation and storage assets are located in Oklahoma on the Muscogee (Creek) Nation reservation and other reservations that may similarly be found to not have been disestablished. While we cannot predict which other reservations may similarly be found not to have been disestablished or the full extent to which civil jurisdiction may be affected, the ruling could significantly impact laws and regulations to which we are subject in Oklahoma, such as taxation and the permitting and siting of energy assets.

State district courts in Oklahoma, applying the analysis in the U.S. Supreme Court’s ruling regarding the Muscogee (Creek) Nation, have ruled ~~on September 30, 2020~~ that the Cherokee, ~~Nation reservation has~~Chickasaw, Seminole and Choctaw reservations likewise have not been ~~disestablished and on October 13, 2020 that the Chickasaw Nation reservation has not been~~ disestablished. ~~We anticipate that similar rulings will be made regarding the Choctaw Nation and Seminole Nation reservations in the near future because the reservations of all five nations share a similar history.~~ On October 1, 2020, the EPA granted approval to the State of Oklahoma under Section 10211(a) of the Safe, Accountable, ~~Flexible,~~ Efficient Transportation Equity Act of 2005 (the “SAFETE Act”) to administer all of the State’s existing EPA-approved regulatory programs to Indian Country within the State, ~~except: Indian allotments~~subject to which Indian titles have not been extinguished; lands that are held in trust by the United States on behalf of any Indian or Tribe; lands that are owned in fee by any Tribe where title was acquired through a treaty with the United States to which such Tribe is a party and that have never been allotted to any citizen or member of such Tribe. The approval extendscertain exceptions, effectively extending the State’s authority for existing EPA-approved regulatory programs to all lands within the State to which the State applied such programs prior to the U.S. Supreme Court’s ruling. For more information, see the “Five Nations Reservations” disclosure in our Annual Report. At this time, we cannot predict how these issues may ultimately be resolved.

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~~ruling regarding~~Suspension of Leases and Permits on Federal Lands

On January 20, 2021, the ~~Muscogee (Creek) Nation reservation. However,~~Acting Secretary of the U.S. Department of the Interior issued an order that, among other things, imposed a temporary suspension on the issuance of fossil fuel authorizations, including leases and permits on federal lands. Although the order says it does not limit existing operations under valid leases, on January 27, 2021, President Biden signed an executive order suspending new oil and gas leasing on federal lands, pending completion of a review of the federal government’s oil and gas permitting and leasing practices. Less than 2% of acreage dedicated to the Partnership falls on federal lands, with most of our federal land acreage dedications located in the Williston Basin.

Regulatory Compliance

The Pipeline and Hazardous Materials Safety Administration is expected to issue several ~~Tribes have expressed dissatisfaction with~~rules in 2021, including but not limited to: 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 consultation process performed in relation to this approval and it is possible that the EPA’s approval under the SAFETE Act could be challenged. Additionally, the SAFETE Act provides that any Tribe in Oklahoma may seek “TreatmentSafety of Gas Gathering Pipelines rule. Other agencies, such as ~~a State” by~~ the EPA, ~~and it is possible~~are also expected to issue new regulations that ~~one or more of the Tribes in Oklahoma~~ may ~~seek such an approval from the EPA. At this time,~~impact our operations. While we cannot predict ~~how these jurisdictional issues~~the outcome of pending or future legislative or regulatory initiatives, we anticipate that pipeline safety and environmental requirements will continue to become more stringent over time. As a result, we may ~~ultimately be resolved.~~incur significant additional costs to comply with the pending regulations, and any other future laws and regulations, which could have a material impact on our costs of and revenues from operations.

~~Environmental~~FERC Update

~~In April 2020,~~On February 18, 2021, FERC issued a renewed Notice of Inquiry (NOI) seeking input on potential revisions to its current policy statement on the ~~federal district court for~~certification of new natural gas transmission facilities. The NOI supplements a 2018 NOI issued by FERC on the ~~district of Montana issued an order vacating~~same topic. Comments on the ~~U.S. Army Corps of Engineers Clean Water Act Section 404 Nationwide Permit 12 (NWP 12) for alleged failure~~NOI are due on May 26, 2021. We are unable 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. The federal district court subsequently limited the order to vacate NWP 12 only with respect to pipeline construction.~~In May 2020, the U.S. Army Corps of Engineers appealed the federal district court’s order to the U.S. Court of Appeals for the Ninth Circuit. In July 2020, the U.S. Supreme Court granted~~predict what, if any, changes may be proposed as a ~~stay~~result of the ~~district court’s order vacating NWP 12, pending the disposition of the appeal in the Ninth Circuit~~NOI that would affect our transportation and storage segment or when such proposals, if any, subsequent appeal to the Supreme Court. Additionally, on September 15, 2020, the U.S. Army Corps of Engineers published a proposal to reissue its existing Nationwide Permits and associated general conditions and definitions, with some modifications, including proposed modifications to NWP 12. That proposal is subject to a 60-day public comment period. While the full extent and impact of the court’s action, as well as the proposed NWP 12 re-issuance, 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.might become effective.

~~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.~~

~~Repurchase of Senior Notes~~

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Results ~~of Operations~~

The following tables summarize the key components of our results of operations.

Three Months Ended September 30, 2020 Gathering and
Processing Transportation
and Storage Eliminations Enable
Midstream
Partners, LP
(In millions)
Product sales $ 271 $ 79 $ (70) $ 280
Service revenues 192 126 (2) 316
Total Revenues 463 205 (72) 596
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 244 78 (72) 250
Gross margin (1)
219 127 — 346
Operation and maintenance, General and administrative 77 47 — 124
Depreciation and amortization 75 30 — 105
Taxes other than income tax 10 7 — 17
Operating income $ 57 $ 43 $ — $ 100

Three Months Ended September 30, 2019 Gathering and
Processing Transportation
and Storage Eliminations Enable
Midstream
Partners, LP
(In millions)
Product sales $ 294 $ 100 $ (74) $ 320
Service revenues 248 134 (3) 379
Total Revenues 542 234 (77) 699
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 238 102 (77) 263
Gross margin (1)
304 132 — 436
Operation and maintenance, General and administrative 79 57 — 136
Depreciation and amortization 77 31 — 108
Taxes other than income tax 10 7 — 17
Operating income $ 138 $ 37 $ — $ 175


Nine Months Ended September 30, 2020		Gathering and Processing		Transportation and Storage		Eliminations		Enable Midstream Partners, LP
Three Months Ended March 31, 2021										Three Months Ended March 31, 2021	Gathering and Processing		Transportation and Storage		Eliminations		Enable Midstream Partners, LP

		(In millions)									(In millions)
Product sales	Product sales	$	739	$	213	$	(188)	$	764	Product sales	$	428	$	332	$	(133)	$	627
Service revenues	Service revenues	592		409		(6)		995		Service revenues	196		150		(3)		343
Total Revenues	Total Revenues	1,331		622		(194)		1,759		Total Revenues	624		482		(136)		970
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	631		215		(193)		653		Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	398		257		(136)		519
Gross margin (1)	Gross margin (1)	700		407		(1)		1,106		Gross margin (1)	226		225		—		451
Operation and maintenance, General and administrative	Operation and maintenance, General and administrative	250		137		(1)		386		Operation and maintenance, General and administrative	79		42		0		121
Depreciation and amortization	Depreciation and amortization	223		91		—		314		Depreciation and amortization	74		32		0		106
Impairments of property, plant and equipment and goodwill		28		—		—		28

Taxes other than income tax	Taxes other than income tax	32		20		—		52		Taxes other than income tax	11		7		0		18
Operating income	Operating income	$	167	$	159	$	—	$	326	Operating income	$	62	$	144	$	0	$	206

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Nine Months Ended September 30, 2019		Gathering and Processing		Transportation and Storage		Eliminations		Enable Midstream Partners, LP
Three Months Ended March 31, 2020										Three Months Ended March 31, 2020	Gathering and Processing		Transportation and Storage		Eliminations		Enable Midstream Partners, LP

		(In millions)									(In millions)
Product sales	Product sales	$	1,096	$	381	$	(321)	$	1,156	Product sales	$	275	$	75	$	(62)	$	288
Service revenues	Service revenues	663		421		(11)		1,073		Service revenues	202		159		(1)		360
Total Revenues	Total Revenues	1,759		802		(332)		2,229		Total Revenues	477		234		(63)		648
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	895		394		(331)		958		Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	211		78		(63)		226
Gross margin (1)	Gross margin (1)	864		408		(1)		1,271		Gross margin (1)	266		156		—		422
Operation and maintenance, General and administrative	Operation and maintenance, General and administrative	238		152		(1)		389		Operation and maintenance, General and administrative	81		45		0		126
Depreciation and amortization	Depreciation and amortization	229		94		—		323		Depreciation and amortization	74		30		0		104

Impairments of property, plant and equipment and goodwill										Impairments of property, plant and equipment and goodwill	28		0		0		28
Taxes other than income tax	Taxes other than income tax	31		21		—		52		Taxes other than income tax	11		7		0		18
Operating income	Operating income	$	366	$	141	$	—	$	507	Operating income	$	72	$	74	$	0	$	146

_____________________

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

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Operating Data:
Natural gas gathered volumes—TBtu 374 411 1,164 1,240
Natural gas gathered volumes—TBtu/d 4.07 4.47 4.25 4.54
Natural gas processed volumes—TBtu (1)
190 229 597 689
Natural gas processed volumes—TBtu/d (1)
2.06 2.49 2.18 2.52
NGLs produced—MBbl/d (1)(2)
133.11 117.78 122.29 128.62
NGLs sold—MBbl/d (2)(3)
138.55 118.29 127.66 131.49
Condensate sold—MBbl/d 5.58 6.16 6.50 7.36
Crude oil and condensate gathered volumes—MBbl/d 138.02 132.99 121.38 120.17
Transported volumes—TBtu 440 549 1,532 1,703
Transported volumes—TBtu/d 4.78 5.97 5.58 6.22
Interstate firm contracted capacity—Bcf/d 5.73 6.02 6.00 6.31
Intrastate average deliveries—TBtu/d 1.74 2.10 1.83 2.16


	Three Months Ended March 31,
		2021	2020

Operating Data:
Natural gas gathered volumes—TBtu		368	411
Natural gas gathered volumes—TBtu/d		4.09	4.52
Natural gas processed volumes—TBtu (1)		185	222
Natural gas processed volumes—TBtu/d (1)		2.06	2.44
NGLs produced—MBbl/d (1)(2)		118.90	120.86
NGLs sold—MBbl/d (2)(3)		119.86	121.32
Condensate sold—MBbl/d		6.78	8.23
Crude oil and condensate gathered volumes—MBbl/d		113.79	141.25
Transported volumes—TBtu		549	597
Transported volumes—TBtu/d		6.10	6.56
Interstate firm contracted capacity—Bcf/d		6.52	6.48
Intrastate average deliveries—TBtu/d		1.65	2.07

_____________________

(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.

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		Three Months Ended September 30,		Nine Months Ended September 30,			Three Months Ended March 31,
		2020	2019	2020	2019			2021	2020
Anadarko	Anadarko					Anadarko
Gathered volumes—TBtu/d	Gathered volumes—TBtu/d	1.94	2.27	2.04	2.32	Gathered volumes—TBtu/d		1.98	2.29
Natural gas processed volumes—TBtu/d (1)	Natural gas processed volumes—TBtu/d (1)	1.76	2.04	1.85	2.07	Natural gas processed volumes—TBtu/d (1)		1.80	2.08
NGLs produced—MBbl/d (1)(2)	NGLs produced—MBbl/d (1)(2)	120.80	103.53	109.29	111.99	NGLs produced—MBbl/d (1)(2)		108.04	106.58
Crude oil and condensate gathered volumes—MBbl/d	Crude oil and condensate gathered volumes—MBbl/d	104.93	91.58	93.65	82.75	Crude oil and condensate gathered volumes—MBbl/d		81.18	114.48
Arkoma	Arkoma					Arkoma
Gathered volumes—TBtu/d	Gathered volumes—TBtu/d	0.41	0.46	0.42	0.48	Gathered volumes—TBtu/d		0.39	0.44
Natural gas processed volumes—TBtu/d (1)	Natural gas processed volumes—TBtu/d (1)	0.08	0.10	0.08	0.10	Natural gas processed volumes—TBtu/d (1)		0.06	0.08
NGLs produced—MBbl/d (1)(2)	NGLs produced—MBbl/d (1)(2)	3.94	4.42	3.96	5.89	NGLs produced—MBbl/d (1)(2)		3.49	3.90
Ark-La-Tex	Ark-La-Tex					Ark-La-Tex
Gathered volumes—TBtu/d	Gathered volumes—TBtu/d	1.72	1.74	1.79	1.74	Gathered volumes—TBtu/d		1.72	1.79
Natural gas processed volumes—TBtu/d	Natural gas processed volumes—TBtu/d	0.22	0.35	0.25	0.35	Natural gas processed volumes—TBtu/d		0.20	0.28
NGLs produced—MBbl/d (2)	NGLs produced—MBbl/d (2)	8.37	9.83	9.04	10.74	NGLs produced—MBbl/d (2)		7.37	10.38
Williston	Williston					Williston
Crude oil gathered volumes—MBbl/d	Crude oil gathered volumes—MBbl/d	33.09	41.41	27.73	37.42	Crude oil gathered volumes—MBbl/d		32.61	26.77

_____________________

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

(2)Excludes condensate.

Gathering and Processing

Three months ended ~~September 30, 2020~~March 31, 2021 compared to three months ended ~~September 30, 2019~~March 31, 2020. Our gathering and processing segment reported operating income of ~~$57~~$62 million for the three months ended ~~September 30, 2020~~March 31, 2021 compared to operating income of ~~$138~~$72 million for the three months ended ~~September 30, 2019.~~March 31, 2020. The difference of ~~$81~~$10 million in operating income between periods was primarily due to ~~an $85~~a $40 million decrease in gross margin, partially offset by $28 million of property, plant and equipment and goodwill impairments recognized in 2020 and a $2 million decrease in operation and maintenance and general and administrative ~~expenses and a $2 million decrease in depreciation and amortization expense during the three months ended September 30, 2020.~~expenses.

Our gathering and processing segment revenues ~~decreased $79~~increased $147 million. The ~~decrease~~increase was primarily due to the following:

Product Sales:

•~~changes in the fair value of natural gas, condensate and NGL derivatives decreased $12 million,~~

•revenues from ~~natural gas sales decreased $11 million due to lower sales volumes, partially offset by higher average sales prices, and~~

• ~~realized gains on natural gas, condensate and NGL derivatives decreased $6 million.~~

~~These decreases were partially offset by revenues from~~ NGL sales ~~which~~ increased $6$130 million primarily due to an increase in the average realized sales price from higher average market prices for ~~all~~ NGL products ~~other than natural gasoline and~~combined with higher recoveries of ethane, ~~in the Anadarko Basin,~~ partially offset by lower ~~sales in the Arkoma~~processed volumes and ~~Ark-La-Tex Basin primarily due to lower processed volumes.~~

~~Service Revenues:~~

•revenues from natural gas ~~gathering revenues decreased $51~~sales increased $56 million due to ~~lower gathered volumes, inclusive of continued producer shut-ins~~higher average sales prices.

These increases were partially offset by:

•changes in the ~~Anadarko Basin that ended during the third quarter, lower shortfall fees associated with the expiration~~fair value of ~~certain minimum volume commitment contracts in the Ark-La-Tex Basin~~natural gas, condensate and ~~lower revenue associated with the third quarter 2019 amendment of certain minimum volume commitment contracts in the Arkoma Basin~~NGL derivatives decreased $19 million and

•realized losses on natural gas, condensate and NGL derivatives, which increased $14 million.

Service Revenues:

•processing service revenues ~~decreased $6~~increased $3 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~~ higher average market prices, ~~as well as~~partially offset by lower processed volumes under fee-based arrangements.

These increases were partially offset by:

•natural gas gathering revenues decreased $8 million due to lower gathered volumes, inclusive of volume curtailments and production freeze-offs related to Winter Storm Uri, partially offset by higher assessed producer imbalance penalties and

•crude oil, condensate and produced water gathering revenue, which decreased $1 million primarily due to a decrease in gathered crude oil and condensate volumes in the Anadarko Basin, partially offset by an increase in gathered crude oil volumes in the ~~recognition of certain annual minimum processing fees.~~Williston Basin.

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These decreases were partially offset by crude oil, condensate and produced water gathering revenues which increased by $1 million primarily due to an increase in gathered crude oil volumes in the Anadarko Basin, partially offset by a decrease in gathered crude oil volumes in the Williston Basin.

Our gathering and processing segment gross margin decreased ~~$85~~$40 million. The decrease was primarily due to the following:

•changes in the fair value of natural gas, ~~gathering fees~~condensate and NGL derivatives decreased ~~$51~~$19 million, due to lower gathered volumes, inclusive of continued producer shut-ins in the Anadarko Basin that ended during the third quarter, lower shortfall fees associated with the expiration of certain minimum volume commitment contracts in the Ark-La-Tex Basin

•realized losses on natural gas, condensate and ~~lower revenue associated with the third quarter 2019 amendment of certain minimum volume commitment contracts in the Arkoma Basin,~~NGL derivatives, which increased $14 million,

•revenues from natural gas sales less the cost of natural gas decreased approximately ~~$15~~$10 million due to higher intra month natural gas purchase costs during Winter Storm Uri,

•natural gas gathering fees decreased $8 million due to lower ~~sales~~gathered volumes, inclusive of volume curtailments and production freeze-offs related to Winter Storm Uri, partially offset by higher ~~average sales prices,~~

•~~changes in the fair value of natural gas, condensate and NGL derivatives decreased $12 million,~~

•~~realized gains on natural gas, condensate and NGL derivatives decreased $6 million,~~assessed producer imbalance penalties, and

•~~processing service~~crude oil, condensate and produced water gathering revenues decreased $6$1 million primarily due to ~~lower processed~~a decrease in gathered crude oil and condensate volumes ~~under fee-based arrangements,~~in the Anadarko Basin, partially offset by ~~higher consideration received from percent-of-proceeds, percent-of-liquids and keep-whole processing arrangements due to~~ an increase in ~~retained~~gathered crude oil volumes ~~at higher average market prices as well as an increase~~ in the ~~recognition of certain annual minimum processing fees.~~Williston Basin.

These decreases were partially offset by:

•revenues from NGL sales less the cost of NGLs increased ~~$4 million due to higher average sales prices for all NGL products other than natural gasoline and~~

•~~crude oil, condensate and produced water gathering revenues increased $1~~$9 million primarily due to an increase in ~~gathered crude oil volumes in~~ the ~~Anadarko Basin,~~average realized sales price from higher average market prices for NGL products combined with higher recoveries of ethane, partially offset by ~~a decrease in gathered crude oil~~lower processed volumes ~~in the Williston Basin.~~and

•processing service fees increased $3 million due to higher consideration received from percent-of-proceeds, percent-of-liquids and keep-whole processing arrangements due to higher average market prices, partially offset by lower processed volumes under fee-based arrangements.

Our gathering and processing segment operation and maintenance and general and administrative expenses decreased $2 million. The decrease was primarily due to a $4$6 million decrease in ~~compressor~~payroll-related costs as a result of lower headcount, a $3 million decrease in field equipment rentals and a $1 million decrease ~~in payroll-related costs.~~due to insurance proceeds partially offset by remediation costs associated with our Williston Basin operations. These decreases were partially offset by a $2$7 million increase in ~~materials and supplies~~professional services primarily due to transaction costs related to the ~~timing of operation and maintenance activities, a $1 million gain on retirement of assets in the prior year~~pending merger with ~~no comparable item in the current year,~~Energy Transfer and a $1 million increase due to lower capitalized overhead costs.

~~Our gathering and processing segment depreciation and amortization decreased $2 million. The decrease was primarily related to new depreciation rates implemented in~~During the ~~prior year which resulted in higher depreciation expense in 2019 for certain assets with shorter remaining useful lives, as compared to 2020, partially offset by additional assets placed in service.~~

~~Nine~~three months ended ~~September 30, 2020 compared to nine months ended September 30, 2019~~. Our gathering and processing segment reported operating income of $167 million for the nine months ended September 30, 2020 compared to operating income of $366 million for the nine months ended September 30, 2019. The difference of $199 million in operating income between periods was primarily due to a $164 million decrease in gross margin, $28 million of property, plant and equipment and goodwill impairments recognized in 2020, a $12 million increase in operation and maintenance and general and administrative expenses and a $1 million increase in taxes other than income tax, partially offset by a $6 million decrease in depreciation and amortization during the nine months ended September 30, 2020.

~~Our gathering and processing segment revenues decreased $428 million. The decrease was primarily due to the following:~~

~~Product Sales:~~

•~~revenues from NGL sales decreased $219 million primarily due to a decrease in the average realized sales price from lower average market prices for NGL products and lower processed volumes,~~

•~~revenues from natural gas sales decreased $130 million due to lower average sales prices and lower sales volumes, and~~

•~~changes in the fair value of natural gas, condensate and NGL derivatives decreased $13 million.~~

~~These decreases were partially offset by realized gains on natural gas, condensate and NGL derivatives, which increased $5 million.~~

~~Service Revenues:~~

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•natural gas gathering revenues decreased $57 million due to lower gathered volumes in the Anadarko and Arkoma Basins, inclusive of continued producer shut-ins in the Anadarko Basin that ended during the third quarter, lower shortfall fees associated with the expiration of certain minimum volume commitment contracts in the Ark-La-Tex and Arkoma Basins and lower revenue associated with the third quarter 2019 amendment of certain minimum volume commitment contracts in the Arkoma Basin,

•processing service revenues decreased $14 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 as well as an increase in the recognition of certain annual minimum processing fees, and

•~~a $1 million decrease in intercompany management fees.~~

These decreases were partially offset by crude oil, condensate and produced water gathering revenue, which increased $1 million primarily due to an increase in gathered crude oil volumes in the Anadarko Basin, partially offset by a decrease in gathered crude oil volumes in the Williston Basin.

~~Our gathering and processing segment gross margin decreased $164 million. The decrease was primarily due to the following:~~

•natural gas gathering fees decreased $57 million due to lower gathered volumes in the Anadarko and Arkoma Basins, inclusive of continued producer shut-ins in the Anadarko Basin that ended during the third quarter, lower shortfall fees associated with the expiration of certain minimum volume commitment contracts in the Ark-La-Tex and Arkoma Basins and lower revenue associated with the third quarter 2019 amendment of certain minimum volume commitment contracts in the Arkoma Basin,

•~~revenues from natural gas sales less the cost of natural gas decreased approximately $53 million due to lower average sales prices and lower sales volumes,~~

•~~revenues from NGL sales less the cost of NGLs decreased $32 million due to lower volumes and lower average market prices for NGL products,~~

•processing service fees decreased $14 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 as well as an increase in the recognition of certain annual minimum processing fees,

•~~changes in the fair value of natural gas, condensate and NGL derivatives decreased $13 million, and~~

•~~a $1 million decrease in intercompany management fees.~~

~~These decreases were partially offset by:~~

•~~realized gains on natural gas, condensate and NGL derivatives, which increased $5 million and~~

•crude oil, condensate and produced water gathering revenues increased $1 million primarily due to an increase in gathered crude oil volumes in the Anadarko Basin, partially offset by a decrease in gathered crude oil volumes in the Williston Basin.

Our gathering and processing segment operation and maintenance and general and administrative expenses increased $12 million. The increase was primarily due to a $19 million increase in loss on retirement of assets driven by a $20 million loss on retirement of an Ark-La-Tex gathering system in 2020 as compared to $1 million in losses on retirement in the prior year, a $4 million increase due to lower capitalized overhead costs, and a $1 million increase in payroll-related costs. These increases were partially offset by an $8 million decrease in compressor rentals, a $2 million decrease in materials and supplies due to the timing of operation and maintenance activities and a $1 million decrease in office and travel expenses due to travel restrictions and employees working remotely.

~~During the nine months ended September 30,~~March 31, 2020, our gathering and processing segment recognized impairments of property, plant and equipment 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. 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 forecast 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 forecast producer activities, the resulting decrease in our forecast 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.

~~Table of Contents~~

Our gathering and processing segment depreciation and amortization decreased $6 million. The decrease was primarily related to new depreciation rates implemented in the prior year which resulted in higher depreciation expense in 2019 for certain assets with shorter remaining useful lives, as compared to 2020, partially offset by additional assets placed in service.

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

Transportation and Storage

Three months ended ~~September 30, 2020~~March 31, 2021 compared to three months ended ~~September 30, 2019~~March 31, 2020. Our transportation and storage segment reported operating income of ~~$43~~$144 million for the three months ended ~~September 30, 2020~~March 31, 2021 compared to operating income of ~~$37~~$74 million for the three months ended ~~September 30, 2019.~~March 31, 2020. The difference of $6$70 million in operating income between periods was primarily due to a ~~$10~~$69 million increase in gross margin, $3 million decrease in operation and maintenance and general and administrative expenses, ~~and a $1 million decrease in depreciation and amortization,~~ partially offset by a $5$2 million ~~decrease~~increase in ~~gross margin.~~depreciation and amortization.

Our transportation and storage segment revenues ~~decreased $29~~increased $248 million. The ~~decrease~~increase was primarily due to the following:

Product Sales:

•revenues from natural gas sales ~~decreased $18~~increased $257 million primarily due to ~~lower sales volumes, partially offset by~~ higher average sales prices,

•volume-dependent transportation and storage revenues increased $6 million due to an increase in assessed shipper imbalance penalties, partially offset by lower off-system intrastate transported volumes due to decreased production activity in the Anadarko Basin, inclusive of disruptions in natural gas supply associated with Winter Storm Uri, and the recognition in 2020 of $1 million of revenue upon the settlement of the MRT rate case with no comparable item in 2021, and

•revenues from NGL sales ~~decreased $3~~increased $1 million due to ~~lower~~higher average sales prices, partially offset by lower volumes.

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These increases were partially offset by changes in the fair value of natural gas derivatives, which decreased $1 million.

Service Revenues:

•firm transportation and storage services decreased $15 million due to the recognition in 2020 of $16 million of previously reserved revenue upon the settlement of the MRT rate case with no comparable item in 2021, partially offset by higher interstate contracted capacity.

Our transportation and storage segment gross margin increased $69 million. The increase was primarily due to the following:

•system management activities increased $74 million primarily due to higher average natural gas sales prices,

•a $5 million reduction in lower of cost or net realizable value adjustments related to natural gas storage inventories.

These increases were partially offset by:

•changes in the fair value of natural gas derivatives, ~~decreased $1 million.~~

~~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 ~~$5 million due to lower off-system intrastate transportation rates and lower transported volumes due to decreased production activity in the Anadarko Basin and~~

•firm transportation and storage services decreased $3 million due to lower interstate contracted capacity, partially offset by higher recognized rates subsequent to the settlement of the MRT rate case.

~~Our transportation and storage segment gross margin decreased $5 million. The decrease was primarily due to the following:~~

•volume-dependent transportation and storage revenues decreased $5 million due to lower off-system intrastate transportation rates and lower transported volumes due to decreased production activity in the Anadarko Basin,

•~~a $2 million decrease due to incremental lower of cost or net realizable value adjustments related to natural gas storage inventories, and~~

•~~changes in the fair value of natural gas derivatives decreased $1 million.~~

~~These decreases were partially offset by:~~

•~~system management activities increased $5 million and~~

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

Our transportation and storage segment operation and maintenance and general and administrative expenses decreased ~~$10~~$3 million. The decrease was primarily driven by a $5 million decrease related to claims settlement costs in the prior year with no comparable activity in the current year, a $4 million reduction in the estimated retirement loss previously recognized in 2019 related to a physical property loss, a $2 million decrease in professional services due to higher rate case costs in the prior year, $1 million decrease in office and travel expenses due to the impact of travel restrictions and employees working remotely and a $1$3 million decrease in payroll-related ~~costs.~~costs as a result of lower headcount and a $3 million decrease in operation and maintenance outside services. These decreases were partially offset by a $4$3 million increase in ~~materials and supplies and outside services due to pipeline safety and storage integrity work under our pipeline safety program and to comply with certain PHMSA regulations.~~the allowance for doubtful accounts.

Our transportation and storage segment depreciation and amortization ~~decreased $1~~increased $2 million primarily due to ~~retirements~~revised estimates of ~~general plant~~remaining useful lives for certain assets.

~~Table of Contents~~

~~Nine months ended September 30, 2020 compared to nine months ended September 30, 2019~~. Our transportation and storage segment reported operating income of $159 million for the nine months ended September 30, 2020 compared to operating income of $141 million for the nine months ended September 30, 2019. The difference of $18 million in operating income between periods was primarily due to a $15 million decrease in operation and maintenance and general and administrative expenses, a $3 million decrease in depreciation and amortization, and a $1 million decrease in taxes other than income tax, partially offset a $1 million decrease in gross margin.

~~Our transportation and storage segment revenues decreased $180 million. The decrease was primarily due to the following:~~

~~Product Sales:~~

•~~revenues from natural gas sales decreased $158 million primarily due to lower sales volumes and lower average sales prices,~~

•~~revenues from NGL sales decreased $9 million due to lower average sales prices and lower volumes, and~~

•~~changes in the fair value of natural gas derivatives decreased $1 million.~~

~~Service Revenues:~~

•volume-dependent transportation and storage revenues decreased $10 million due to lower off-system intrastate transportation rates and lower transported volumes due to decreased production activity in the Anadarko Basin, partially offset by the recognition of $1 million of revenue upon the settlement of the MRT rate case and

•firm transportation and storage services decreased $2 million due to lower interstate contracted capacity and lower rates on certain contracts for intrastate service with power generators, partially offset by an increase in recognized rates and the recognition of $16 million of previously reserved revenue upon the settlement of the MRT rate case.

~~Our transportation and storage segment gross margin decreased $1 million. The decrease was primarily due to the following:~~

•~~a $3 million decrease due to incremental lower of cost or net realizable value adjustments related to natural gas storage inventories,~~

•~~revenues from NGL sales less the cost of NGLs decreased $2 million due to a decrease in average NGL prices and lower volumes,~~

•~~changes in the fair value of natural gas derivatives decreased $1 million.~~

~~These decreases were partially offset by system management activities, which increased $17 million.~~

Our transportation and storage segment operation and maintenance and general and administrative expenses decreased $15 million. The decrease was primarily driven by a $7 million reduction in the estimated retirement loss previously recognized in 2019 related to a physical property loss in addition to a gain on retirement in the current year, a $5 million decrease related to claims settlement costs in the prior year with no comparable activity in the current year, a $4 million decrease in professional services due to higher rate case costs in the prior year, a $2 million decrease in payroll-related costs, a $2 million decrease in office and travel expenses due to the impact of travel restrictions and employees working remotely and a $1 million decrease in intercompany management fees. These decreases were partially offset by a $6 million increase in materials and supplies and outside services due to pipeline safety and storage integrity work under our pipeline safety program and to comply with certain PHMSA regulations and a $1 million increase due to lower capitalized overhead costs.

~~Our transportation and storage segment depreciation and amortization decreased $3 million primarily due to retirements of general plant assets.~~

~~Our transportation and storage segment taxes other than income tax decreased $1 million due to favorable tax settlements.~~

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Condensed Consolidated Interim Information


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020

		(In millions)										(In millions)
Operating Income	Operating Income	$	100	$	175	$	326	$	507	Operating Income		$	206	$	146
Other Income (Expense):	Other Income (Expense):									Other Income (Expense):
Interest expense	Interest expense	(43)		(48)		(136)		(142)		Interest expense		(42)		(47)
Equity in earnings (losses) of equity method affiliate, net (1)		(222)		5		(211)		12
Other, net		2		1		7		2
Equity in earnings of equity method affiliate, net (1)										Equity in earnings of equity method affiliate, net (1)		1		6

Total Other Expense	Total Other Expense	(263)		(42)		(340)		(128)		Total Other Expense		(41)		(41)
Income (Loss) Before Income Taxes		(163)		133		(14)		379
Income Before Income Taxes										Income Before Income Taxes		165		105
Income tax benefit	Income tax benefit	—		—		—		(1)		Income tax benefit		0		0
Net Income (Loss)		$	(163)	$	133	$	(14)	$	380
Net Income										Net Income		$	165	$	105
Less: Net income (loss) attributable to noncontrolling interest	Less: Net income (loss) attributable to noncontrolling interest	1		1		(6)		2		Less: Net income (loss) attributable to noncontrolling interest		1		(7)
Net Income (Loss) Attributable to Limited Partners		$	(164)	$	132	$	(8)	$	378
Net Income Attributable to Limited Partners										Net Income Attributable to Limited Partners		$	164	$	112
Less: Series A Preferred Unit distributions	Less: Series A Preferred Unit distributions	9		9		27		27		Less: Series A Preferred Unit distributions		9		9
Net Income (Loss) Attributable to Common Units		$	(173)	$	123	$	(35)	$	351
Net Income Attributable to Common Units										Net Income Attributable to Common Units		$	155	$	103

_____________________

(1)See Item 1 Note 8 of Part I for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three ~~and nine~~ months ended ~~September 30, 2020~~March 31, 2021 and ~~2019.~~2020.

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Three Months Ended ~~September 30, 2020~~March 31, 2021 compared to Three Months Ended ~~September 30, 2019~~March 31, 2020

Net Income ~~(Loss)~~ Attributable to Limited Partners. We reported net ~~loss~~income attributable to limited partners of $164 million in the three months ended ~~September 30, 2020~~March 31, 2021 compared to net income attributable to limited partners of ~~$132~~$112 million in the three months ended ~~September 30, 2019.~~March 31, 2020. The ~~decrease~~increase in net income attributable to limited partners of ~~$296~~$52 million was primarily attributable to ~~a decrease in equity in earnings (losses) of equity method affiliate, net of $227 million and a decrease~~an increase in operating income of ~~$75~~$60 million ~~partially offset by~~and a decrease in interest expense of $5 million, partially offset by an $8 million change in net income (loss) attributable to noncontrolling interest in the prior year and ~~an increase~~a decrease in ~~other,~~equity in earnings of equity method affiliate, net of $1$5 million in the three months ended ~~September 30, 2020.~~March 31, 2021.

Equity in Earnings ~~(Losses)~~ of Equity Method Affiliate, net. Equity in earnings ~~(losses)~~ of equity method affiliate, net decreased ~~$227~~$5 million ~~primarily~~ due to a ~~$225 million impairment~~decrease in revenues as a result of contract expirations, partially offset by an increase in amortization of the ~~Partnership’s equity method affiliate investment in the third quarter of 2020.~~basis differential.

Interest Expense. Interest expense decreased $5 million primarily due to lower ~~interest rates on the Partnership’s short-term borrowings.~~

~~Nine Months Ended September 30, 2020 compared to Nine Months Ended September 30, 2019~~

~~Net Income (Loss) Attributable to Limited Partners.~~ We reported net loss attributable to limited partners of $8 million in the nine months ended September 30, 2020 compared to net income attributable to limited partners of $378 million in the nine months ended September 30, 2019. The decrease in net income attributable to limited partners of $386 million was primarily attributable to a decrease in equity in earnings (losses) of equity method affiliate, net of $223 million, a decrease in operating income of $181 million, debt levels and an income tax benefit of $1 million in the prior year with no tax effect in the current year, partially offset by a decrease in interest expense of $6 million, an increase in other, net of $5 million and an $8 million change in net income (loss) attributable to noncontrolling interest in the nine months ended September 30, 2020.

~~Equity in Earnings (Losses) of Equity Method Affiliate, net.~~ Equity in earnings (losses) of equity method affiliate, net decreased $223 million primarily due to a $225 million impairment of the Partnership’s equity method affiliate investment in the third quarter of 2020.

~~Interest Expense.~~ ~~Interest expense decreased $6 million primarily due to~~ lower interest rates on the Partnership’s short-term borrowings.

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~~Other, net.~~ ~~Other, net increased $5 million primarily due to a gain on extinguishment of debt.~~

Net Income (Loss) Attributable to Noncontrolling Interest. Net income (loss) attributable to noncontrolling interest changed $8 million primarily due to an impairment in 2020 in the Partnership’s Atoka assets of which the Partnership owns a 50% interest in the consolidated joint venture.

Reconciliations of Non-GAAP Financial Measures

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

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

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions)
Reconciliation of Gross margin to Total Revenues:
Consolidated
Product sales $ 280 $ 320 $ 764 $ 1,156
Service revenues 316 379 995 1,073
Total Revenues 596 699 1,759 2,229
Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 250 263 653 958
Gross margin $ 346 $ 436 $ 1,106 $ 1,271
Reportable Segments
Gathering and Processing
Product sales $ 271 $ 294 $ 739 $ 1,096
Service revenues 192 248 592 663
Total Revenues 463 542 1,331 1,759
Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 244 238 631 895
Gross margin $ 219 $ 304 $ 700 $ 864
Transportation and Storage
Product sales $ 79 $ 100 $ 213 $ 381
Service revenues 126 134 409 421
Total Revenues 205 234 622 802
Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 78 102 215 394
Gross margin $ 127 $ 132 $ 407 $ 408

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	Three Months Ended March 31,
		2021		2020

		(In millions)
Reconciliation of Gross margin to Total Revenues:
Consolidated
Product sales		$	627	$	288
Service revenues		343		360
Total Revenues		970		648
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)		519		226
Gross margin		$	451	$	422

Reportable Segments
Gathering and Processing
Product sales		$	428	$	275
Service revenues		196		202
Total Revenues		624		477
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)		398		211
Gross margin		$	226	$	266

Transportation and Storage
Product sales		$	332	$	75
Service revenues		150		159
Total Revenues		482		234
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)		257		78
Gross margin		$	225	$	156

The following table shows the components of our gross margin.


		Fee-Based (1)									Fee-Based (1)
Nine Months Ended September 30, 2020		Demand		Volume- Dependent		Commodity- Based (1)		Total
Three Months Ended March 31, 2021										Three Months Ended March 31, 2021	Demand		Volume- Dependent		Commodity- Based (1)		Total
Gathering and Processing Segment	Gathering and Processing Segment	15	%	69	%	16	%	100	%	Gathering and Processing Segment	11	%	76	%	13	%	100	%
Transportation and Storage Segment	Transportation and Storage Segment	91	%	9	%	—	%	100	%	Transportation and Storage Segment	56	%	10	%	34	%	100	%
Partnership Weighted Average	Partnership Weighted Average	43	%	47	%	10	%	100	%	Partnership Weighted Average	34	%	42	%	24	%	100	%

____________________

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

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions, except Distribution coverage ratio)
Reconciliation of Adjusted EBITDA and DCF to net income (loss) attributable to limited partners and calculation of Distribution coverage ratio:
Net income (loss) attributable to limited partners $ (164) $ 132 $ (8) $ 378
Depreciation and amortization expense 105 108 314 323
Interest expense, net of interest income 43 48 135 141
Income tax benefit — — — (1)
Distributions received from equity method affiliate in excess of equity earnings 1 (1) 9 8
Impairment of equity method affiliate investment 225 — 225 —
Non-cash equity-based compensation 3 4 10 13
Change in fair value of derivatives (1)
15 2 17 3
Other non-cash losses (2)
1 2 23 9
Impairments of property, plant and equipment and goodwill — — 28 —
Gain on extinguishment of debt — — (5) —
Noncontrolling Interest Share of Adjusted EBITDA — — (9) (1)
Adjusted EBITDA $ 229 $ 295 $ 739 $ 873
Series A Preferred Unit distributions (3)
(9) (9) (27) (27)
Distributions for phantom and performance units (4)
— (1) (1) (10)
Adjusted interest expense (5)
(42) (47) (134) (143)
Maintenance capital expenditures (31) (36) (69) (86)
Current income taxes — — 1 —
DCF $ 147 $ 202 $ 509 $ 607
Distributions related to common unitholders (6)
$ 72 $ 144 $ 216 $ 426
Distribution coverage ratio (7)
2.04 1.40 2.36 1.42

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	Three Months Ended March 31,
		2021		2020

		(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		$	164	$	112
Depreciation and amortization expense		106		104
Interest expense, net of interest income		42		47

Distributions received from equity method affiliate in excess of equity earnings		3		4

Non-cash equity-based compensation		4		4
Change in fair value of derivatives (1)		10		(10)
Other non-cash (gains) losses (2)		(1)		5
Impairments of property, plant and equipment and goodwill		—		28

Noncontrolling Interest Share of Adjusted EBITDA		—		(8)
Adjusted EBITDA		$	328	$	286
Series A Preferred Unit distributions (3)		(9)		(9)

Adjusted interest expense (4)		(42)		(47)
Maintenance capital expenditures		(16)		(16)

DCF		$	261	$	214

Distributions related to common unitholders (5)		$	72	$	72

Distribution coverage ratio (6)		3.63		2.97

____________________

(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 (gains) losses includes write-downs and ~~net~~gains and loss on sale and retirement of assets.

(3)This amount represents the quarterly cash distributions on the Series A Preferred Units declared for the three ~~and nine~~ months ended ~~September 30, 2020~~March 31, 2021 and ~~2019.~~2020. 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)~~(5)Represents cash distributions declared for common units outstanding as of each respective period. Amounts for ~~2020~~2021 reflect estimated cash distributions for common units outstanding for the quarter ended ~~September 30, 2020.~~March 31, 2021.

~~Table of Contents~~

~~(7)~~(6)Distribution coverage ratio is computed by dividing DCF by Distributions related to common unitholders.

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions)
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities $ 232 $ 264 $ 543 $ 691
Interest expense, net of interest income 43 48 135 141
Noncontrolling interest share of cash provided by operating activities (1) (1) (3) (2)
Current income taxes — — 1 —
Other non-cash items (1)
(2) — — 4
Proceeds from insurance 1 — 1 —
Changes in operating working capital which (provided) used cash:
Accounts receivable 3 41 (27) (16)
Accounts payable (24) (2) 46 110
Other, including changes in noncurrent assets and liabilities (39) (56) 17 (66)
Return of investment in equity method affiliate 1 (1) 9 8
Change in fair value of derivatives (2)
15 2 17 3
Adjusted EBITDA $ 229 $ 295 $ 739 $ 873

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	Three Months Ended March 31,
		2021		2020

		(In millions)
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities		$	223	$	200
Interest expense, net of interest income		42		47
Noncontrolling interest share of cash provided by operating activities		(1)		(1)

Other non-cash items (1)		(3)		4
Proceeds from insurance		1		—
Changes in operating working capital which (provided) used cash:
Accounts receivable		34		(60)
Accounts payable		(10)		58
Other, including changes in noncurrent assets and liabilities		29		44
Return of investment in equity method affiliate		3		4
Change in fair value of derivatives (2)		10		(10)

Adjusted EBITDA		$	328	$	286

____________________

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

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


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020

		(In millions)										(In millions)
Reconciliation of Adjusted interest expense to Interest expense:	Reconciliation of Adjusted interest expense to Interest expense:									Reconciliation of Adjusted interest expense to Interest expense:
Interest expense	Interest expense	$	43	$	48	$	136	$	142	Interest expense		$	42	$	47
Interest income		—		—		(1)		(1)

Amortization of premium on long-term debt	Amortization of premium on long-term debt	—		1		1		4		Amortization of premium on long-term debt		—		1
Capitalized interest on expansion capital	Capitalized interest on expansion capital	1		—		2		1		Capitalized interest on expansion capital		1		—
Amortization of debt expense and discount	Amortization of debt expense and discount	(2)		(2)		(4)		(3)		Amortization of debt expense and discount		(1)		(1)
Adjusted interest expense	Adjusted interest expense	$	42	$	47	$	134	$	143	Adjusted interest expense		$	42	$	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.

~~Table of Contents~~

~~Working Capital~~

Working capital is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from, customers, the level and timing of spending for maintenance and expansion activity, and the timing of debt maturities. As of September 30, 2020, we had a working capital deficit of $271 million. The deficit is primarily due to ~~$334 million of commercial paper outstanding as of~~ ~~September 30, 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.~~

Nine Months Ended September 30,
2020 2019
(In millions)
Net cash provided by operating activities $ 543 $ 691
Net cash used in investing activities $ (120) $ (353)
Net cash used in financing activities $ (409) $ (347)

~~Operating Activities~~

The decrease of $148 million or 21%, in net cash provided by operating activities for the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019 was primarily driven by a decrease in net income of $394 million and a decrease of $8 million in the timing of cash receipts and disbursements and changes in other working capital assets and liabilities, partially offset by an increase in adjustments for non-cash items of $254 million.

~~Investing Activities~~

The decrease of $233 million, or 66%, in net cash used in investing activities for the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019 was primarily due to lower capital expenditures of $201 million, partially offset by an increase in proceeds from sale of $18 million due to the sale of the Partnership’s interest in the Bistineau Storage Facility, an increase in other investing cash flows of $12 million, an increase in return of investment in equity method affiliate of $1 million and an increase in proceeds from insurance of $1 million.

~~Financing Activities~~

Net cash used in financing activities increased $62 million, or 18%, for the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019. Our primary financing activities consist of the following:

Nine Months Ended September 30,
2020 2019
(In millions)
Increase (decrease) in short-term debt $ 179 $ (467)
Proceeds from long-term debt, net of issuance costs — 1,544
Repayment of 2019 Senior Notes — (500)
Repayment of term loans — (200)
Repurchase of 2029 Senior Notes and 2044 Senior Notes (17) —
Repayment of EOIT Senior Notes (250) —
Net proceeds (repayments) of Revolving Credit Facility — (250)
Distributions (320) (450)
Cash paid for employee equity-based compensation (1) (24)

~~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.~~

~~Table of Contents~~

~~Sources of Liquidity~~

~~As of September 30, 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~~.

~~ATM Program~~

~~Distributions~~

On November 3, 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 September 30, 2020. The distributions will be paid November 24, 2020 to unitholders of record as of the close of business on November 17, 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 November 13, 2020 to unitholders of record as of the close of business on November 3, 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 redu~~ction 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 depressed commodity price environment caused by the oversupply of crude oil, NGLs and natural gas and 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 ~~September 30, 2020~~March 31, 2021 are the same as those described in our Annual Report as modified for the adoption of new accounting standards and for the impairment of equity method affiliate investment disclosed in Item 1. “Financial Statements, Notes to Unaudited Condensed Consolidated Financial Statements.”Report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

~~Table of Contents~~

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,

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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 forecast volumes, prices and contractual arrangements, we estimate approximately ~~10%~~13% of our total gross margin for the twelve months ended December 31, ~~2020~~2021 is directly exposed to changes in commodity prices, excluding the impact of hedges and contractual floors related to commodity prices in certain agreements. Since ~~September 30, 2020,~~March 31, 2021, we have entered into additional derivative contracts to further manage our exposure to commodity price risk for the remaining ~~three~~nine months ending December 31, ~~2020.~~2021.

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 ~~three~~nine months. Based on a sensitivity analysis regarding our direct commodity exposure, a 10% decrease in prices from forecast levels would decrease net income by approximately $3$8 million for natural gas and ethane and $2$12 million for NGLs (other than ethane) and condensate, excluding the impact of hedges, for the remaining ~~three~~nine months ending December 31, ~~2020.~~

The impact of the ongoing COVID-19 pandemic and the economic effects of the pandemic have resulted in a significant decrease in the price of natural gas, NGL and crude oil. The economic effects of the COVID-19 pandemic 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.2021.

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt ~~portfolio.~~portfolio and distributions on the Series A Preferred Units. 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 2019 Term Loan Agreement and any issuances under our commercial paper program and distributions on our Series A Preferred Units 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 ~~$1.1~~$1.0 billion outstanding borrowings under commercial paper and 2019 Term Loan Agreement as of ~~September 30, 2020,~~March 31, 2021, 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 ~~$11~~$10 million. For further information regarding our interest rates, see Note 9 of the Notes to the Condensed Consolidated Financial Statements.

Beginning February 18, 2021, distributions on the Series A Preferred Units, when declared, are calculated at a floating rate equal to the sum of the three-month LIBOR plus 8.5%. Based upon the $362 million outstanding under the Series A Preferred Units as of March 31, 2021, holding all variables constant, a 100 basis-point, or 1%, increase in interest rates would increase our Series A Preferred Unit annual distributions by $4 million. For further information regarding the Series A Preferred Units, see Note 6 of the Notes to the Condensed Consolidated Financial Statements.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Exchange Act) as of ~~September 30, 2020.~~March 31, 2021. Based on such evaluation, our management has concluded that, as of ~~September 30, 2020,~~March 31, 2021, 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.

~~Table of Contents~~

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

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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 ~~September 30, 2020,~~March 31, 2021, 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. Risk factors relating to the Partnership are set forth under “Risk Factors” in our Annual ~~Report and March 31 Quarterly~~ Report. No other material changes to such risk factors have occurred during the three months ended ~~September 30, 2020.~~March 31, 2021.

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.

5345

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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

2.2

Agreement and Plan of Merger, dated as of February 16, 2021 by and among Energy Transfer LP, Elk Merger Sub LLC, Elk GP Merger Sub LLC, Enable Midstream Partners, LP, Enable GP, LLC, solely for purposes of Section 2.1(a)(i) therein, LE GP, LLC and, solely for purposes of Section 1.1(b)(i), CenterPoint Energy, Inc.**

Registrant’s Form 8-K filed
February 17, 2021

File No. 001-36413

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 May 27, 2014, by and among Enable Midstream Partners, LP, CenterPoint Energy Resources Corp., as guarantor, and RBS Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA) LLC, and RBC Capital Markets, LLC, as representatives of the initial purchasers

Registrant’s Form 8-K filed May 29, 2014

File No. 001-36413

Exhibit 4.3

4.5

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~~4.6

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~~4.7

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~~4.8

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

10.1

Support Agreement, dated as of February 16, 2021, by and among Energy Transfer LP, Elk Merger Sub LLC, Elk GP Merger Sub LLC, Enable Midstream Partners, LP, Enable GP, LLC and CenterPoint Energy, Inc.

Registrant’s Form 8-K filed
February 17, 2021

File No. 001-36413

Exhibit 10.1

10.2

Support Agreement, dated as of February 16, 2021, by and among Energy Transfer LP, Elk Merger Sub LLC, Elk GP Merger Sub LLC, Enable Midstream Partners, LP, Enable GP, LLC and OGE Energy Corp.

Registrant’s Form 8-K filed
February 17, 2021

File No. 001-36413

Exhibit 10.2

+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.

5446

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SIGNATURE

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

ENABLE MIDSTREAM PARTNERS, LP

(Registrant)

By: ENABLE GP, LLC

Its general partner

Date:

~~November 4, 2020~~May 3, 2021

By:

/s/ Tom Levescy

Tom Levescy

Senior Vice President, Chief Accounting Officer and Controller

(Principal Accounting Officer)

5547


			Page
GLOSSARY OF TERMS			1
FORWARD-LOOKING STATEMENTS			34

Part I - FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Statements of Income			56
Condensed Consolidated Statements of Comprehensive Income			67
Condensed Consolidated Balance Sheets			78
Condensed Consolidated Statements of Cash Flows			89
Condensed Consolidated Statements of Partners' Equity			910
Notes to Unaudited Condensed Consolidated Financial Statements			1011
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations			3330
Item 3. Quantitative and Qualitative Disclosures About Market Risk			5143
Item 4. Controls and Procedures			5244

Part II - OTHER INFORMATION
Item 1. Legal Proceedings			5345
Item 1A. Risk Factors			5345

Item 6. Exhibits			5345

Signature			5547


	September 30, 2020		January 1, 2020

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


	Three Months Ended September 30, 2020
	Gathering and Processing		Transportation and Storage		Eliminations		Total

	(In millions)
Revenues:
Product sales:
Natural gas	$	58	$	77	$	(68)	$	67
Natural gas liquids	208		2		(2)		208
Condensate	15		0		0		15
Total revenues from natural gas, natural gas liquids, and condensate	281		79		(70)		290
Loss on derivative activity	(10)		0		0		(10)
Total Product sales	$	271	$	79	$	(70)	$	280
Service revenues:
Demand revenues	$	32	$	116	$	0	$	148
Volume-dependent revenues	160		10		(2)		168
Total Service revenues	$	192	$	126	$	(2)	$	316
Total Revenues	$	463	$	205	$	(72)	$	596


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

	(In millions)
Revenues:
Product sales:
Natural gas	$	69	$	95	$	(69)	$	95
Natural gas liquids	191		5		(5)		191
Condensate	26		0		0		26
Total revenues from natural gas, natural gas liquids, and condensate	286		100		(74)		312
Gain on derivative activity	8		0		0		8
Total Product sales	$	294	$	100	$	(74)	$	320
Service revenues:
Demand revenues	$	97	$	119	$	0	$	216
Volume-dependent revenues	151		15		(3)		163
Total Service revenues	$	248	$	134	$	(3)	$	379
Total Revenues	$	542	$	234	$	(77)	$	699


	September 30, 2020		December 31, 2019		Amounts recognized in revenues

	(In millions)
Deferred revenues (1)	$	44	$	48	$	23


	September 30,
	2020		2019

	(In millions)
Cash and cash equivalents	$	18	$	12
Restricted cash	0		1
Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	18	$	13