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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

_______________________________________

FORM 10-Q

_______________________________________


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

For the quarterly period ended ~~June~~September 30, 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

☒

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 ~~July~~October 1615, 2021, there were 435,~~877~~891,~~546~~855 common units outstanding.

Table of Contents

ENABLE MIDSTREAM PARTNERS, LP

FORM 10-Q

TABLE OF CONTENTS

			Page
GLOSSARY OF TERMS			1
FORWARD-LOOKING STATEMENTS			4
Part I - FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Statements of Income			6
Condensed Consolidated Statements of Comprehensive Income			7
Condensed Consolidated Balance Sheets			8
Condensed Consolidated Statements of Cash Flows			9
Condensed Consolidated Statements of Partners' Equity			10
Notes to Unaudited Condensed Consolidated Financial Statements			11
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations			3435
Item 3. Quantitative and Qualitative Disclosures About Market Risk			5051
Item 4. Controls and Procedures			5152
Part II - OTHER INFORMATION
Item 1. Legal Proceedings			5253
Item 1A. Risk Factors			5253
Item 6. Exhibits			5253
Signature			5455

AVAILABLE INFORMATION

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

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

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

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

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

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

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

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

Table of Contents

GLOSSARY OF TERMS

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.
MMcf/d.			Million cubic feet per day.
TBtu.			Trillion British thermal units.
TBtu/d.			Trillion British thermal units per day.
Abbreviations
AFUDC			Allowance for funds used during construction.
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.
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.
FTC.			United States Federal Trade 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.
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.
NYSE.			New York Stock Exchange.
OPEC.			Organization of the Petroleum Exporting Countries.

Table of Contents

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, equity AFUDC and 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, 2020.
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.
Board of Directors.			The board of directors of Enable GP, LLC.
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.
Corps.			United States Army Corps of Engineers.
Distribution coverage ratio.			A non-GAAP measure calculated as DCF divided by distributions related to common unitholders.
Enable GP.			Enable GP, LLC, the general partner of Enable Midstream Partners, LP.
EOIT Senior Notes.			$250 million aggregate principal amount of EOIT’s 6.25% senior notes that were repaid in March 2020.
Energy Transfer.			Energy Transfer LP, a Delaware limited partnership, and its subsidiaries.
Exchange Act.			Securities Exchange Act of 1934, as amended.
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.
HSR Act.			Hart-Scott-Rodino Antitrust Improvements Act.
Merger.			The acquisition of the Partnership by Energy Transfer Partners, LP.

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Merger Agreement.			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.
OGE Energy.			OGE Energy Corp., an Oklahoma corporation, and its subsidiaries.
Partnership.			Enable Midstream Partners, LP and its subsidiaries.
Partnership Agreement.			Fifth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP dated as of November 14, 2017.

Revolving Credit Facility.			$1.75 billion senior unsecured revolving credit facility.


Series A Preferred Units.			10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in the Partnership.

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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.

All 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 Merger of the Partnership with and into Energy Transfer LP pursuant to 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. Those risk factors and other factors noted throughout this report and in our Annual Report could cause our actual results to differ materially from those disclosed in any forward-looking statement. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

•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 continued 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 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~~its 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;

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

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•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.

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 June 30,				Six Months EndedJune 30,
	Three Months Ended September 30,				Nine Months EndedSeptember 30,
	2021		2020		2021		2020
	(In millions, except per unit data)
Revenues (including revenues from affiliates (Note 13)):
Product sales	$	~~460~~623	$	~~196~~280	$	1,~~087~~710	$	~~484~~764
Service revenues	~~327~~333		~~319~~316		~~670~~1,003		~~679~~995
Total Revenues	~~787~~956		~~515~~596		12,~~757~~713		1,~~163~~759
Cost and Expenses (including expenses from affiliates (Note 13)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	~~426~~565		~~177~~250		~~945~~1,510		~~403~~653
Operation and maintenance	9192		~~115~~96		~~175~~267		~~217~~313
General and administrative	2527		2128		6289		4573
Depreciation and amortization	~~103~~104		105		~~209~~313		~~209~~314
Impairments of property, plant and equipment and goodwill (Note 7)	—		—		—		28
Taxes other than income tax	1816		17		3652		3552
Total Cost and Expenses	~~663~~804		~~435~~496		12,~~427~~231		~~937~~1,433
Operating Income	~~124~~152		80100		~~330~~482		~~226~~326
Other Income (Expense):
Interest expense	(4241)		(4643)		(84125)		(93136)
Equity in earnings of equity method affiliate	—		5		1		11
Equity in earnings (losses) of equity method affiliate, net	4		(222)		5		(211)
Other, net	61		52		67		57
Total Other Expense	(36)		(36263)		(77113)		(77340)
Income Before Income Tax	88		44		253		149
Income (Loss) Before Income Tax	116		(163)		369		(14)
Income tax benefit	—		—		—		—
Net Income	$	88	$	44	$	253	$	149
Net Income (Loss)	$	116	$	(163)	$	369	$	(14)
Less: Net income (loss) attributable to noncontrolling interest	1—		—1		2		(76)
Net Income Attributable to Limited Partners	$	87	$	44	$	251	$	156
Net Income (Loss) Attributable to Limited Partners	$	116	$	(164)	$	367	$	(8)
Less: Series A Preferred Unit distributions (Note 6)	89		9		1726		1827
Net Income Attributable to Common Units (Note 5)	$	79	$	35	$	234	$	138
Net Income (Loss) Attributable to Common Units (Note 5)	$	107	$	(173)	$	341	$	(35)
Basic and diluted earnings per unit (Note 5)
Basic and diluted earnings (loss) per unit (Note 5)
Basic	$	0.1824	$	(0.0840)	$	0.5378	$	(0.3208)
Diluted	$	0.1824	$	(0.0840)	$	0.5276	$	(0.3008)

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 June 30,				Six Months EndedJune 30,
	Three Months Ended September 30,				Nine Months EndedSeptember 30,
	2021		2020		2021		2020
	(In millions)
Net income	$	88	$	44	$	253	$	149
Net income (loss)	$	116	$	(163)	$	369	$	(14)
Other comprehensive income (loss):
Change in fair value of interest rate derivative instruments	—		—		—		(67)
Reclassification of interest rate derivative losses to net income	21		—2		34		—3
Other comprehensive income (loss)	21		—2		34		(64)
Comprehensive income	90		44		256		143
Comprehensive income (loss)	117		(161)		373		(18)
Less: Comprehensive income (loss) attributable to noncontrolling interest	1—		—1		2		(76)
Comprehensive income attributable to Limited Partners	$	89	$	44	$	254	$	150
Comprehensive income (loss) attributable to Limited Partners	$	117	$	(162)	$	371	$	(12)

See Notes to the Unaudited Condensed Consolidated Financial Statements

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ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2021		December 31, 2020
	September 30, 2021		December 31, 2020
	(In millions)
Current Assets:
Cash and cash equivalents	$	2836	$	3
Accounts receivable, net of allowance for doubtful accounts (Note 1)	~~326~~384		248
Accounts receivable—affiliated companies	129		15
Inventory	43		42
Gas imbalances	2826		42
Other current assets, net of allowance for doubtful accounts (Note 1)	38		31
Total current assets	~~475~~536		381
Property, Plant and Equipment:
Property, plant and equipment	13,~~354~~396		13,220
Less: Accumulated depreciation and amortization	2,~~715~~785		2,555
Property, plant and equipment, net	10,~~639~~611		10,665
Other Assets:
Intangible assets, net	~~508~~492		539
Investment in equity method affiliate	7376		76
Other	6465		68
Total other assets	~~645~~633		683
Total Assets	$	11,~~759~~780	$	11,729
Current Liabilities:
Accounts payable	$	~~161~~220	$	149
Accounts payable—affiliated companies	2		2
Current portion of long-term debt	800		—
Short-term debt	~~171~~50		250
Taxes accrued	4655		34
Gas imbalances	1428		19
Other	~~123~~144		128
Total current liabilities	1,~~317~~299		582
Other Liabilities:
Accumulated deferred income taxes, net	4		5
Regulatory liabilities	2627		25
Other	6663		71
Total other liabilities	9694		101
Long-Term Debt	3,~~153~~154		3,951
Commitments and Contingencies (Note 14)
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at June 30, 2021 and December 31, 2020)	362		362
Series A Preferred Units (14,520,000 issued and outstanding at September 30, 2021 and December 31, 2020)	362		362
Common Units (435,866,139 issued and outstanding at June 30, 2021 and 435,549,892 issued and outstanding at December 31, 2020)	6,809		6,713
Common Units (435,877,546 issued and outstanding at September 30, 2021 and 435,549,892 issued and outstanding at December 31, 2020)	6,848		6,713
Accumulated other comprehensive loss	(32)		(6)
Noncontrolling interest	25		26
Total Partners’ Equity	7,~~193~~233		7,095
Total Liabilities and Partners’ Equity	$	11,~~759~~780	$	11,729

See Notes to the Unaudited Condensed Consolidated Financial Statements

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ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	Nine Months Ended September 30,
	2021		2020
	(In millions)
Cash Flows from Operating Activities:
Net income	$	253	$	149
Net income (loss)	$	369	$	(14)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	~~209~~313		~~209~~314
Deferred income taxes	—		1
Impairments of property, plant and equipment and goodwill	—		28
Net loss on sale/retirement of assets	—1		17
Equity in earnings of equity method affiliate	(1)		(11)
Equity in (earnings) losses of equity method affiliate, net	(5)		211
Return on investment in equity method affiliate	15		1114
Equity-based compensation	812		710
Amortization of debt costs and discount	34		13
Other, net	(67)		(5)
Changes in other assets and liabilities:
Accounts receivable, net	(78136)		2014
Accounts receivable—affiliated companies	36		1013
Inventory	(1)		34
Gas imbalance assets	1416		(3)
Other current assets, net	(911)		~~(10)~~—
Other assets	3		34
Accounts payable	1467		(7147)
Accounts payable—affiliated companies	—		1
Gas imbalance liabilities	~~(5)~~9		—(5)
Other current liabilities	642		(4514)
Other liabilities	(19)		(43)
Net cash provided by operating activities	~~413~~678		~~311~~543
Cash Flows from Investing Activities:
Capital expenditures (excluding equity AFUDC)	(~~151~~204)		(~~102~~152)
Proceeds from sale of assets	3		19
Return of investment in equity method affiliate	3		8
Proceeds from insurance	—		1
Other, net	2		2
Return of investment in equity method affiliate	—		9
Net cash used in investing activities	(143)		(73)
Other, net	3		3
Net cash used in investing activities	(198)		(120)
Cash Flows from Financing Activities:
Decrease in short-term debt	(79200)		~~(125)~~179
Repayment of long-term debt	—		(267)
Proceeds from Revolving Credit Facility	—		869
Repayment of Revolving Credit Facility	—		(~~469~~869)
Distributions to common unitholders	(~~144~~216)		(~~216~~288)
Distributions to preferred unitholders	(1726)		(1827)
Distributions to non-controlling interests	(3)		(35)
Cash paid for employee equity-based compensation	(2)		(21)
Net cash used in financing activities	(~~245~~447)		(~~231~~409)
Net Increase in Cash, Cash Equivalents and Restricted Cash	2533		714
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	3		4
Cash, Cash Equivalents and Restricted Cash at End of Period	$	2836	$	1118

See Notes to the Unaudited Condensed Consolidated Financial Statements

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ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

(Unaudited)

	Six Months Ended June 30, 2021
	Nine Months Ended September 30, 2021
	Series A PreferredUnits			Common Units			Accumulated Other Comprehensive Loss		NoncontrollingInterest		Total Partners’Equity
	Units	Value		Units	Value		Value		Value		Value
	(In millions)
Balance as of December 31, 2020	15	$	362	435	$	6,713	$	(6)	$	26	$	7,095
Net income	—	9		—	155		—		1		165
Other comprehensive income	—	—		—	—		1		—		1
Distributions	—	(9)		—	(72)		—		(1)		(82)
Equity-based compensation, net of units for employee taxes	—	—		1	2		—		—		2
Balance as of March 31, 2021	15	$	362	436	$	6,798	$	(5)	$	26	$	7,181
Net income	—	8		—	79		—		1		88
Other comprehensive income	—	—		—	—		2		—		2
Distributions	—	(8)		—	(72)		—		(2)		(82)
Equity-based compensation, net of units for employee taxes	—	—		—	4		—		—		4
Balance as of June 30, 2021	15	$	362	436	$	6,809	$	(3)	$	25	$	7,193
Net income	—	9		—	107		—		—		116
Other comprehensive income	—	—		—	—		1		—		1
Distributions	—	(9)		—	(72)		—		—		(81)
Equity-based compensation, net of units for employee taxes	—	—		—	4		—		—		4
Balance as of September 30, 2021	15	$	362	436	$	6,848	$	(2)	$	25	$	7,233

	Six Months Ended June 30, 2020
	Nine Months Ended September 30, 2020
	Series A Preferred Units			Common Units			Accumulated Other Comprehensive Loss		Noncontrolling Interest		Total Partners’ Equity
	Units	Value		Units	Value		Value		Value		Value
	(In millions)
Balance as of December 31, 2019	15	$	362	435	$	7,013	$	(3)	$	37	$	7,409
Net income (loss)	—	9		—	103		—		(7)		105
Other comprehensive loss	—	—		—	—		(6)		—		(6)
Distributions	—	(9)		—	(144)		—		(3)		(156)
Equity-based compensation, net of units for employee taxes	—	—		—	3		—		—		3
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)	—	—		—	(3)		—		—		(3)
Balance as of March 31, 2020	15	$	362	435	$	6,972	$	(9)	$	27	$	7,352
Net income	—	9		—	35		—		—		44
Distributions	—	(9)		—	(72)		—		—		(81)
Equity-based compensation, net of units for employee taxes	—	—		—	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 loss	—	—		—	—		2		—		2
Distributions	—	(9)		—	(72)		—		(2)		(83)
Equity-based compensation, net of units for employee taxes	—	—		—	3		—		—		3
Balance as of September 30, 2020	15	$	362	435	$	6,695	$	(7)	$	26	$	7,076

See Notes to the Unaudited Condensed Consolidated Financial Statements

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ENABLE MIDSTREAM PARTNERS, LP

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

Organization

Enable Midstream Partners, LP (the Partnership) is a Delaware limited partnership whose 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 gathering and 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. 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 two representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership’s Chief Executive Officer and three independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP.

As of ~~June~~September 30, 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 ~~June~~September 30, 2021, the Partnership owned a 50% interest in SESH. See Note 8 for further discussion of SESH. For the ~~six~~nine months ended ~~June~~September 30, 2021, the Partnership owned a 50% ownership in Atoka and consolidated Atoka in 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 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 16, 2021, the Partnership and Energy Transfer entered 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 the ~~second~~fourth ~~half~~quarter of 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~~its economic effects, ~~of the pandemic~~ which have continued to cause significant volatility in natural gas, NGLs and crude oil prices.

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 ~~three~~nine months ended ~~June~~ September 30, 2020, which is included in Operation and maintenance expense in the Condensed Consolidated Statements of Income.

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.

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	June 30, 2021		December 31, 2020
	September 30, 2021		December 31, 2020
	(In millions)
Accounts receivable	$	31	$	1
Other current assets	21		3
Total Allowance for doubtful accounts	$	52	$	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 zero and $12 million during the three months ended ~~June~~September 30, 2021 and 2020, respectively, and $1 million and $79 million during the ~~six~~nine months ended ~~June~~September 30, 2021 and 2020, respectively.

Impairment of 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.

Impairment of Investment in Equity Method Affiliate

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 equal to the difference, is recorded to Equity in earnings (losses) of equity method affiliate, net. 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.

Capitalization of Interest and Allowance for Funds Used During Construction

Capitalized interest represents the approximate net composite interest cost of borrowed funds used for construction of assets other than those assets regulated by FERC. Allowance for funds used during construction (AFUDC) is separated into two components, borrowed funds (debt AFUDC) and equity funds (equity AFUDC). AFUDC is calculated under guidelines prescribed by FERC, and represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction of FERC regulated assets. Although equity AFUDC increases both utility plant and earnings, it is realized in cash when the assets are included in rates for entities that apply guidance for accounting for regulated operations. Interest and AFUDC are capitalized as a component of projects under construction and will be amortized over the assets’ estimated useful lives. Capitalized interest and the borrowed funds component of AFUDC are recognized as an offset to Interest expense and the equity funds component of AFUDC is recognized in Other, net on the Condensed Consolidated Statements of Income. The Partnership capitalized interest and combined debt and equity AFUDC of $6 million and $1 million during the three months ended June 30, 2021 and 2020, respectively, and $7 million and $1 million during the six months ended June 30, 2021 and 2020, respectively.

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earnings, it is realized in cash when the assets are included in rates for entities that apply guidance for accounting for regulated operations. Interest and AFUDC are capitalized as a component of projects under construction and will be amortized over the assets’ estimated useful lives. Capitalized interest and the borrowed funds component of AFUDC are recognized as an offset to Interest expense and the equity funds component of AFUDC is recognized in Other, net on the Condensed Consolidated Statements of Income. The Partnership capitalized interest and combined debt and equity AFUDC of $3 million and $1 million during the three months ended September 30, 2021 and 2020, respectively, and $10 million and $2 million during the nine months ended September 30, 2021 and 2020, respectively.

(2) New Accounting Pronouncements

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

In January 2021, the FASB issued ASU 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 the first quarter of 2021. The implementation had no material impact on 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 ~~six~~nine months ended ~~June~~September 30, 2021 and 2020.

	Three Months Ended June 30, 2021
	Three Months Ended September 30, 2021
	Gathering andProcessing		Transportationand Storage		Eliminations		Total
	(In millions)
Revenues:
Product sales:
Natural gas	$	91128	$	~~133~~158	$	(~~131~~154)	$	93132
Natural gas liquids	~~361~~485		5		(5)		~~361~~485
Condensate	3534		—		—		3534
Total revenues from natural gas, natural gas liquids, and condensate	~~487~~647		~~138~~163		(~~136~~159)		~~489~~651
Loss on derivative activity	(2622)		(36)		—		(2928)
Total Product sales	$	~~461~~625	$	~~135~~157	$	(~~136~~159)	$	~~460~~623
Service revenues:
Demand revenues	$	3130	$	~~107~~110	$	—	$	~~138~~140
Volume-dependent revenues	~~181~~184		1112		(3)		~~189~~193
Total Service revenues	$	~~212~~214	$	~~118~~122	$	(3)	$	~~327~~333
Total Revenues	$	~~673~~839	$	~~253~~279	$	(~~139~~162)	$	~~787~~956

	Three Months Ended June 30, 2020
	Three Months Ended September 30, 2020
	Gathering andProcessing		Transportationand Storage		Eliminations		Total
	(In millions)
Revenues:
Product sales:
Natural gas	$	4758	$	5777	$	(5368)	$	5167
Natural gas liquids	~~143~~208		32		(32)		~~143~~208
Condensate	715		—		—		715
Total revenues from natural gas, natural gas liquids, and condensate	~~197~~281		6079		(5670)		~~201~~290
Loss on derivative activity	(410)		~~(1)~~—		—		(510)
Total Product sales	$	~~193~~271	$	5979	$	(5670)	$	~~196~~280
Service revenues:
Demand revenues	$	3432	$	~~113~~116	$	—	$	~~147~~148
Volume-dependent revenues	~~164~~160		1110		(32)		~~172~~168
Total Service revenues	$	~~198~~192	$	~~124~~126	$	(32)	$	~~319~~316
Total Revenues	$	~~391~~463	$	~~183~~205	$	(5972)	$	~~515~~596

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	Six Months Ended June 30, 2021
	Nine Months Ended September 30, 2021
	Gathering andProcessing		Transportationand Storage		Eliminations		Total
	(In millions)
Revenues:
Product sales:
Natural gas	$	~~203~~331	$	~~463~~621	$	(~~261~~415)	$	~~405~~537
Natural gas liquids	~~658~~1,143		813		(813)		~~658~~1,143
Condensate	67101		—		—		67101
Total revenues from natural gas, natural gas liquids, and condensate	~~928~~1,575		~~471~~634		(~~269~~428)		1,~~130~~781
Loss on derivative activity	(3961)		(410)		—		(4371)
Total Product sales	$	~~889~~1,514	$	~~467~~624	$	(~~269~~428)	$	1,~~087~~710
Service revenues:
Demand revenues	$	5787	$	~~234~~344	$	—	$	~~291~~431
Volume-dependent revenues	~~351~~535		3446		(69)		~~379~~572
Total Service revenues	$	~~408~~622	$	~~268~~390	$	(69)	$	~~670~~1,003
Total Revenues	$	12,~~297~~136	$	~~735~~1,014	$	(~~275~~437)	$	12,~~757~~713

	Six Months Ended June 30, 2020
	Nine Months Ended September 30, 2020
	Gathering andProcessing		Transportationand Storage		Eliminations		Total
	(In millions)
Revenues:
Product sales:
Natural gas	$	~~103~~161	$	~~130~~207	$	(~~113~~181)	$	~~120~~187
Natural gas liquids	~~315~~523		57		(57)		~~315~~523
Condensate	3449		—		—		3449
Total revenues from natural gas, natural gas liquids, and condensate	~~452~~733		~~135~~214		(~~118~~188)		~~469~~759
Gain (loss) on derivative activity	166		(1)		—		155
Total Product sales	$	~~468~~739	$	~~134~~213	$	(~~118~~188)	$	~~484~~764
Service revenues:
Demand revenues	$	73105	$	~~255~~371	$	—	$	~~328~~476
Volume-dependent revenues	~~327~~487		2838		(46)		~~351~~519
Total Service revenues	$	~~400~~592	$	~~283~~409	$	(46)	$	~~679~~995
Total Revenues	$	~~868~~1,331	$	~~417~~622	$	(~~122~~194)	$	1,~~163~~759

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 was inclusive of interest.

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Accounts Receivable

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

	June 30, 2021		December 31, 2020
	September 30, 2021		December 31, 2020
	(In millions)
Accounts Receivable:
Customers	$	~~301~~385	$	245
Contract assets (1)	313		12
Non-customers	65		6
Total Accounts Receivable (2)	$	~~338~~393	$	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 $11 million as of ~~June~~September 30, 2021 and $9 million as of December 31, 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.

	June 30, 2021		December 31, 2020
	September 30, 2021		December 31, 2020
	(In millions)
Deferred revenues, beginning of period (1)	$	44	$	48
Amounts recognized in revenues related to the beginning balance	(1921)		(25)
Net additions	20		21
Deferred revenues, end of period (1)	$	4543	$	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 ~~June~~September 30, 2021.

	2021		2022		2023		2024		2025 and After
	(In millions)
Deferred revenues (1)	$	2217	$	78	$	78	$	7	$	23

____________________

(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 ~~June~~September 30, 2021.

	2021		2022		2023		2024		2025 and After
	(In millions)
Transportation and Storage	$	~~221~~114	$	~~404~~422	$	~~355~~364	$	~~265~~270	$	~~959~~1,143
Gathering and Processing	6030		122		121		101		213
Total remaining performance obligations	$	~~281~~144	$	~~526~~544	$	~~476~~485	$	~~366~~371	$	1,~~172~~356

(4) Leases

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

	Balance Sheet Location	~~June~~September 30, 2021		December 31, 2020
		(In millions)
Operating lease asset	Other Assets	$	23	$	25
Total right-of-use assets		$	23	$	25
Operating lease liabilities	Other Current Liabilities	$	4	$	4
Operating lease liabilities	Other Liabilities	22		24
Total lease liabilities		$	26	$	28

As of ~~June~~September 30, 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 June 30,				Six Months EndedJune 30,
	Three Months Ended September 30,				Nine Months EndedSeptember 30,
	2021		2020		2021		2020
	(In millions)
Rental Costs:
Field equipment	$	2	$	43	$	57	$	912
Office space	2		1		35		23

As of ~~June~~September 30, 2021, the weighted average remaining lease term is 6.31 years and the weighted average discount rate is 5.4954%.

The following table presents the Partnership’s lease cost.

	Three Months Ended June 30,				Six Months EndedJune 30,
	Three Months Ended September 30,				Nine Months EndedSeptember 30,
	2021		2020		2021		2020
	(In millions)
Lease Cost:
Operating lease cost	$	21	$	12	$	34	$	35
Short-term lease cost	2		42		46		79
Variable lease cost	—1		—		12		1
Total Lease Cost	$	4	$	54	$	812	$	1115

All lease costs were included in the gathering and processing reportable segment during the three and ~~six~~nine months ended ~~June~~September 30, 2021 and 2020.

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

	Non-cancellable operating leases
	(In millions)
Year Ending December 31,
2021 - remainder	$	31
2022	56
2023	56
2024	4
2025	3
2026	2
After 2026	6
Total	28
Less: impact of the applicable discount rate	2
Total lease liabilities	$	26

(5) Earnings Per Limited Partner Unit

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

	Three Months Ended June 30,				Six Months EndedJune 30,
	Three Months Ended September 30,				Nine Months EndedSeptember 30,
	2021		2020		2021		2020
	(In millions, except per unit data)
Net income	$	88	$	44	$	253	$	149
Net income (loss)	$	116	$	(163)	$	369	$	(14)
Net income (loss) attributable to noncontrolling interest	1—		—1		2		(76)
Series A Preferred Unit distributions	89		9		1726		1827
Net income available to common units	$	79	$	35	$	234	$	138
Net income (loss) available to common units	$	107	$	(173)	$	341	$	(35)
Net income allocable to common units	$	79	$	35	$	234	$	138
Net income (loss) allocable to common units	$	107	$	(173)	$	341	$	(35)
Dilutive effect of Series A Preferred Unit distributions	—8		—		1726		18—
Diluted net income allocable to common units	$	79	$	35	$	251	$	156
Diluted net income (loss) allocable to common units	$	115	$	(173)	$	367	$	(35)
Basic weighted average number of common units outstanding (1)	438		437		438		437
Dilutive effect of Series A Preferred Units	—		—		41		79
Dilutive effect of Series A Preferred Units (2)	46		—		46		—
Dilutive effect of performance units (2)	1		—		—		—
Dilutive effect of performance units (3)	1		—		1		—
Diluted weighted average number of common units outstanding	~~439~~485		437		~~479~~485		~~516~~437
Basic and diluted earnings per unit
Basic and diluted earnings (losses) per unit
Basic	$	0.1824	$	(0.0840)	$	0.5378	$	(0.3208)
Diluted	$	0.1824	$	(0.0840)	$	0.5276	$	(0.3008)

____________________

(1)Basic weighted average number of outstanding common units includes approximately ~~three million and~~ two million time-based phantom units for each of the three months ended ~~June~~September 30, 2021 and 2020, respectively, and two million time-based phantom units for each of the ~~six~~nine months ended ~~June~~September 30, 2021 and 2020, respectively.

(2)~~The~~For ~~dilutive~~the ~~effect~~three ofand ~~the~~nine ~~performance~~months ~~unit~~ended ~~awards~~September ~~was~~30, ~~less~~2020, ~~than~~the ~~$0.01~~issuance ~~per~~of ~~unit~~“if ~~during~~converted” common units attributable to the ~~three~~Series ~~months~~A ~~ended~~Preferred ~~June~~Units ~~30,~~were ~~2020~~excluded ~~and~~in the ~~six~~calculation ~~months~~of ~~ended~~diluted ~~June~~earnings ~~30,~~(loss) ~~2021~~per ~~and~~unit ~~2020~~as the impact was anti-dilutive.

(3)The contingent effect of the performance unit awards was anti-dilutive for the three and nine months ended September 30, 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 2021 and 2020 (in millions, except for per unit amounts):

Three Months Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
June 30, 2021 (1)	August 12, 2021	August 24, 2021	$	0.16525	$	72
September 30, 2021 (1)	November 8, 2021	November 17, 2021	$	0.16525	$	72
June 30, 2021	August 12, 2021	August 24, 2021	$	0.16525	$	72
March 31, 2021	May 13, 2021	May 25, 2021	$	0.16525	$	72
December 31, 2020	February 22, 2021	March 1, 2021	$	0.16525	$	72
September 30, 2020	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

_____________________

(1)The Board of Directors declared a $0.16525 per common unit cash distribution on ~~July~~October 3026, 2021, to be paid on ~~August~~November 2417, 2021 to common unitholders of record at the close of business on ~~August~~November 128, 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 is included for each relevant period in the table below.

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

Three Months Ended	Record Date	Payment Date	Distribution Rate		Per Unit Distribution		Total Cash Distribution
June 30, 2021 (1)	July 30, 2021	August 13, 2021	8.7016	%	$	0.5439	$	8
September 30, 2021 (1)	October 26, 2021	November 12, 2021	8.6449	%	$	0.5403	$	8
June 30, 2021	July 30, 2021	August 13, 2021	8.7016	%	$	0.5439	$	8
March 31, 2021 (2)	April 26, 2021	May 14, 2021	8.7375	%	$	0.5873	$	9
December 31, 2020	February 12, 2021	February 12, 2021	10.0	%	$	0.625	$	9
September 30, 2020	November 3, 2020	November 13, 2020	10.0	%	$	0.625	$	9
June 30, 2020	August 4, 2020	August 14, 2020	10.0	%	$	0.625	$	9
March 31, 2020	May 5, 2020	May 15, 2020	10.0	%	$	0.625	$	9

_____________________

(1)The Board of Directors declared a $0.~~5439~~5403 per Series A Preferred Unit cash distribution on ~~July~~October 3026, 2021, to be paid on ~~August~~November 1312, 2021, to Series A Preferred unitholders of record at the close of business on ~~July~~October 3026, 2021.

(2)The distribution rate for the three months ended March 31, 2021 reflects 10% through February 18, 2021, and the sum of the three-month LIBOR plus 8.5% for the remaining days in the period.

(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~~its economic effects ~~of the pandemic~~, together with the dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia, as of March 31, 2020, management reassessed the carrying value of the Atoka assets, in which the Partnership owns a 50% interest in the consolidated joint venture, which is a component of the gathering and processing segment. Based on forecasted future undiscounted cash flows, management determined that the carrying value of the Atoka assets were not fully recoverable. The Partnership utilized the income approach (generally accepted valuation approach) to estimate the fair value of these assets. The primary inputs were forecasted cash flows and the discount

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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 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 ~~six~~nine months ended ~~June~~September 30, 2020.

Impairment of Goodwill

InThe Partnership tests its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the ~~fourth~~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 its economic effects, 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 ~~2017~~nations including Russia and Saudi Arabia to reduce production of crude oil, asthe price of NGLs and crude oil had remained significantly lower than pre-pandemic levels. Amid such crude oil, NGL and natural gas price declines, producers 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 ~~result~~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 ~~acquisition~~same time, unit prices and market multiples for midstream companies with gathering and processing operations 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 ~~ETGP~~capital, the Partnership ~~recorded~~determined ~~$12~~that ~~million~~the fair value of the goodwill associated with ~~the~~our Ark-La-Tex Basin reporting unit would more likely than not be impaired. As a result, ~~included~~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 ~~gathering~~amount of $12 million. The impairment is included in Impairments of property, plant and ~~processing~~equipment ~~reportable~~and ~~segment~~goodwill on the Condensed Consolidated Statements of Income for the nine months ended September 30, 2020. The Partnership had no goodwill recorded as of September 30, 2021 and December 31, 2020.

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 had remained significantly lower than pre-pandemic levels. Amid such crude oil, NGL and natural gas price declines, producers 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 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 six months ended June 30, 2020. The Partnership had no goodwill recorded as of June 30, 2021 and December 31, 2020.

(8) Investment in Equity Method Affiliate

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

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

~~The~~At September 30, 2020, the Partnership ~~shares~~estimated ~~operations~~the fair value of its investment in SESH ~~with~~was ~~Enbridge,~~below ~~Inc.~~the ~~under~~carrying ~~service~~value ~~agreements.~~and ~~The~~concluded ~~Partnership~~the isdecline ~~responsible~~in ~~for~~value was other than temporary due to the ~~field~~expiration ~~operations~~of a transportation contract and the current status of ~~SESH~~renewal negotiations. ~~SESH~~As ~~reimburses~~a ~~each~~result, ~~party~~the Partnership recorded a $225 million impairment on its investment in SESH for ~~actual~~the ~~costs~~three ~~incurred~~and nine months ended September 30, 2020, which ~~are~~is ~~billed~~included ~~based~~in ~~upon~~Equity ain ~~combination~~earnings (losses) of ~~direct~~equity ~~charges~~method ~~and~~affiliate, ~~allocations~~net in the Partnership’s Condensed Consolidated Statements of Income. The impairment analysis of the Partnership’s ~~billed~~investment in SESH $3compared ~~million~~the ~~and~~estimated $2fair ~~million~~value ~~during~~of the ~~three~~investment ~~months~~to ~~ended~~its ~~June~~carrying ~~30,~~value. ~~2021~~The ~~and~~fair ~~2020,~~value ~~respectively,~~of the investment was determined using multiple valuation methodologies under both the market and $5income ~~million~~approaches. Due to the significant unobservable estimates and $8assumptions ~~million~~required, ~~during~~the Partnership concluded that the ~~six~~fair ~~months~~value ~~ended~~estimate ~~June~~should 30be 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, ~~2021~~plant and ~~2020,~~equipment ~~respectively,~~and ~~associated~~will ~~with~~be ~~these~~amortized ~~service~~over ~~agreements~~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 $2 million and $3 million during the three months ended September 30, 2021 and 2020, respectively, and $7 million and $11 million during the nine months ended September 30,

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~~The~~2021 ~~Partnership~~and ~~includes~~2020, ~~equity in earnings of equity method affiliate~~respectively, ~~net~~associated ~~under~~with ~~the~~these ~~Other~~service ~~Income (Expense) caption in the Condensed Consolidated Statements of Income~~agreements. ~~The following table presents the amount of Equity in earnings of equity method affiliate recognized and Distributions from equity method affiliate received.~~

	Three Months Ended June 30,				Six Months EndedJune 30,
	2021		2020		2021		2020
	(In millions)
Equity in earnings of equity method affiliate	$	—	$	5	$	1	$	11
Distributions from equity method affiliate (1)	—		9		4		19

The Partnership includes equity in earnings (losses) 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,
	2021		2020		2021		2020

	(In millions)
Equity in earnings of equity method affiliate	$	4	$	3	$	5	$	14
Impairment of equity method affiliate investment	—		(225)		—		(225)
Equity in earnings (losses) of equity method affiliate, net	$	4	$	(222)	$	5	$	(211)
Distributions from equity method affiliate (1)	1		4		5		23

___________________

(1)Distributions from equity method affiliate includes a ~~zero and~~ $5 million ~~return on investment~~ and ~~a zero and~~ $414 million return ~~of investment for the three months ended June 30, 2021 and 2020, respectively. Distributions from equity method affiliate includes a $1 million and $11 million return~~ on investment and a $3zero ~~million~~ and $89 million return of investment for the ~~six~~nine months ended ~~June~~September 30, 2021 and 2020, respectively.

The following table includes the summarized financial information of SESH.

	Three Months Ended June 30,				Six Months EndedJune 30,
	Three Months Ended September 30,				Nine Months EndedSeptember 30,
	2021		2020		2021		2020
	(In millions)
Income Statements:
Revenues	$	1620	$	2824	$	3151	$	5579
Operating income	28		1311		614		2940
Net income (loss)	(1)		10		(2)		21
Net income	3		6		1		27

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(9) Debt

The following table presents the Partnership’s outstanding debt.

	June 30, 2021						December 31, 2020
	September 30, 2021						December 31, 2020
	Outstanding Principal		Discount (1)		Total Debt		Outstanding Principal		Discount (1)		Total Debt
	(In millions)
Commercial Paper	$	~~171~~50	$	—	$	~~171~~50	$	250	$	—	$	250
Revolving Credit Facility	—		—		—		—		—		—
2019 Term Loan Agreement	800		—		800		800		—		800
2024 Notes	600		—		600		600		—		600
2027 Notes	700		(21)		~~698~~699		700		(2)		698
2028 Notes	800		(4)		796		800		(5)		795
2029 Notes	547		(1)		546		547		(1)		546
2044 Notes	531		—		531		531		—		531
Total debt	$	4,~~149~~028	$	(76)	$	4,~~142~~022	$	4,228	$	(8)	$	4,220
Less: Short-term debt (2)					~~171~~50						250
Less: Current portion of long-term debt (3)					800						—
Less: Unamortized debt expense (4)					18						19
Total long-term debt					$	3,~~153~~154					$	3,951

____________________

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

(2)Short-term debt includes $~~171~~50 million and $250 million of outstanding commercial paper as of ~~June~~September 30, 2021 and December 31, 2020, respectively.

(3)As of ~~June~~September 30, 2021, Current portion of long-term debt included $800 million outstanding balance of the 2019 Term Loan Agreement.

(4)As of ~~June~~September 30, 2021 and December 31, 2020, there was an additional $2 million and $3 million, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above.

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Commercial Paper

The Partnership has a commercial paper program, pursuant to which the Partnership is authorized to issue up to $1.4 billion of commercial paper. The commercial paper program is supported by our Revolving Credit Facility, and outstanding commercial paper effectively reduces our borrowing capacity thereunder. There were $~~171~~50 million and $250 million outstanding under our commercial paper program at ~~June~~September 30, 2021 and December 31, 2020, respectively. As of ~~June~~September 30, 2021, the weighted average interest rate for the outstanding commercial paper was 0.4240%.

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 two times to extend the term of the Revolving Credit Facility, in each case, for an additional one-year term. As of ~~June~~September 30, 2021, there were no principal advances, $3 million letters of credit outstanding and our available borrowing capacity was approximately $1.25 billion under our Revolving Credit Facility.

The Revolving Credit Facility provides that outstanding borrowings bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s designated credit ratings from S&P, Moody’s and Fitch Ratings. As of ~~June~~September 30, 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 ~~June~~September 30, 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 ~~June~~September 30, 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 two times, to extend the maturity date for an additional one-year term. The 2019 Term Loan Agreement provides that outstanding borrowings bear interest at the eurodollar rate and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s credit ratings. The applicable margin shall equal, (1) in the case of interest rates determined by reference to the eurodollar rate, between 0.75% and 1.50% per annum and (2) in the case of interest rates determined by reference to the alternate base rate, between 0% and 0.50% per annum. As of ~~June~~September 30, 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 ~~June~~September 30, 2021, the weighted average interest rate of the 2019 Term Loan Agreement was 2.0706%, including the impact of the associated interest rate derivatives designated as hedging instruments for accounting purposes.

Senior Notes

As of ~~June~~September 30, 2021, the Partnership’s debt included the 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes and 2044 Notes, which had $76 million of unamortized discount and $18 million of unamortized debt expense at ~~June~~September 30, 2021, resulting in effective interest rates of 4.0100%, 4.56%, 5.1918%, 4.30% and 5.08%, respectively, during the ~~six~~nine months ended ~~June~~September 30, 2021. In March 2020, the Partnership’s EOIT Senior Notes matured and were paid using proceeds from the Revolving Credit Facility.

During the ~~three~~nine months ended ~~June~~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 ~~June~~September 30, 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.

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Derivatives Not Designated as Hedging Instruments

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

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Quantitative Disclosures Related to Derivative Instruments Not Designated as Hedging Instruments

The following table presents the Partnership’s derivative instruments that were not designated as hedging instruments for accounting purposes.

	June 30, 2021		December 31, 2020
	September 30, 2021		December 31, 2020
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas— TBtu (1)
Financial fixed futures/swaps	—	84	—	18
Financial basis futures/swaps	—1	2211	—	27
Financial swaptions (2)	—	42	—	7
Physical purchases/sales	—	—	—	—
Crude oil (for condensate)— MBbl (3)
Financial futures/swaps	—	~~270~~180	—	465
Financial swaptions (2)	—	9060	—	90
Natural gas liquids— MBbl (4)
Financial futures/swaps	4530	~~525~~300	855	1,210
Financial options	—	15—	—	45

____________________

(1)As of ~~June~~September 30, 2021, 9897.76% of the natural gas contracts had durations of one year or less and 12.34% had durations of more than one year and less than two years. As of December 31, 2020, 95.7% of the natural gas contracts had durations of one year or less and 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 ~~June~~September 30, 2021, 9193.7% of the crude oil (for condensate) contracts had durations of one year or less and 86.3% had durations of more than one year and less than two years. As of December 31, 2020, 100.0% of the crude oil (for condensate) contracts had durations of one year or less.

(4)As of ~~June~~September 30, 2021, 9495.95% of the natural gas liquids contracts had durations of one year or less and 54.15% had durations of more than one year and less than two years. As of December 31, 2020, 100.0% of the natural gas liquids contracts had durations of one year or 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.

	June 30, 2021		December 31, 2020
	September 30, 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.

		June 30, 2021				December 31, 2020
		September 30, 2021				December 31, 2020
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	—	$	913	$	2	$	2
Financial swaptions	Other Current	—		612		1		2
Crude oil (for condensate)
Financial futures/swaps	Other Current	—		75		1		13
Financial swaptions	Other Current	—		12		—		—
Financial swaptions	Other	—		1—		—		—
Natural gas liquids
Financial futures/swaps	Other Current	43		109		15		3
Financial swaptions	Other Current	—		1—		—		1
Total gross commodity derivatives (1)		$	43	$	3541	$	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 ~~June~~September 30, 2021 and December 31, 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.

June 30, 2021

December 31, 2020

September 30, 2021

December 31, 2020

Fair Value

Instrument

Balance Sheet Location

Assets

Liabilities

Assets

Liabilities

(In millions)

Interest rate swaps (1)

Other Current

—

_____________________

(1)All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of ~~June~~September 30, 2021 and December 31, 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
	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020

	(In millions)
Natural gas
Financial futures/swaps losses	$	(16)	$	(5)	$	(29)	$	(2)
Financial swaptions losses	(6)		(4)		(11)		(6)
Physical purchases/sales losses	—		(1)		—		—
Crude oil (for condensate)
Financial futures/swaps gains (losses)	(1)		—		(13)		12
Financial swaptions gains (losses)	—		—		(2)		2
Natural gas liquids
Financial futures/swaps losses	(5)		—		(16)		(1)
Total	$	(28)	$	(10)	$	(71)	$	5

~~Table~~For ofderivatives ~~Contents~~not designated as hedges in the tables above, amounts recognized in income for the periods ended September 30, 2021 and 2020, if any, are reported in Product sales.

	Amounts Recognized in Income
	Three Months Ended June 30,				Six Months EndedJune 30,
	2021		2020		2021		2020
	(In millions)
Natural gas
Financial futures/swaps gains (losses)	$	(11)	$	(1)	$	(13)	$	3
Financial swaptions losses	(5)		(1)		(5)		(2)
Physical purchases/sales gains (losses)	—		—		—		1
Crude oil (for condensate)
Financial futures/swaps gains (losses)	(6)		(7)		(12)		12
Financial swaptions gains (losses)	(1)		(2)		(2)		2
Natural gas liquids
Financial futures/swaps gains (losses)	(6)		6		(11)		(1)
Total	$	(29)	$	(5)	$	(43)	$	15

For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended June 30, 2021 and 2020, 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 June 30,				Six Months EndedJune 30,
	Three Months Ended September 30,				Nine Months EndedSeptember 30,
	2021		2020		2021		2020
	(In millions)
Change in fair value of commodity derivatives	$	(197)	$	(1215)	$	(2936)	$	(217)
Realized gains (losses) on commodity derivatives	(1021)		75		(1435)		1722
Gains (losses) on commodity derivative activity	$	(2928)	$	(510)	$	(4371)	$	155

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 June 30,				Six Months EndedJune 30,
	Three Months Ended September 30,				Nine Months EndedSeptember 30,
	2021		2020		2021		2020
	(In millions)
Interest rate swaps losses	$	(21)	$	(12)	$	(34)	$	(13)

Interest rate derivatives designated as hedges are recognized in income once settled. Settlement amounts recognized in income for the periods ended ~~June~~September 30, 2021 and 2020 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 ~~June~~September 30, 2021, under these obligations, the Partnership had posted $110 million of cash collateral related to natural gas swaps and swaptions, crude oil swaps and swaptions and NGL swaps and $6 million of additional collateral would be required to be posted by the Partnership in the event of a credit ratings downgrade to a below investment grade rating. In certain situations where the Partnership’s credit rating is lowered by Moody’s or S&P, the Partnership could be subject to an early termination event related to certain derivative instruments, which could result in a cash settlement of the instruments at market values on the date of such early termination.

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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 ~~six~~nine months ended ~~June~~September 30, 2021, there were no transfers between levels. As of ~~June~~September 30, 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.

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

	June 30, 2021				December 31, 2020
	September 30, 2021				December 31, 2020
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Debt
Revolving Credit Facility (Level 2) (1)	$	—	$	—	$	—	$	—
2019 Term Loan Agreement (Level 2)	800		800		800		800
2024 Notes (Level 2)	600		~~639~~637		600		612
2027 Notes (Level 2)	~~698~~699		~~774~~776		698		709
2028 Notes (Level 2)	796		~~916~~900		795		817
2029 Notes (Level 2)	546		~~599~~593		546		544
2044 Notes (Level 2)	531		~~578~~581		531		499

____________________

(1) Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $~~171~~50 million and $250 million of commercial paper was outstanding as of ~~June~~September 30, 2021 and December 31, 2020, respectively.

The fair value of the Partnership’s Revolving Credit Facility, 2019 Term Loan Agreement, 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes, and 2044 Notes is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy.

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

Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment). As of ~~June~~September 30, 2021, no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities.

Based upon review of forecasted undiscounted cash flows as of ~~June~~September 30, 2021, all of the asset groups were considered recoverable. Based upon review for other than temporary declines in fair value, the investment in equity method affiliate was considered 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~~supply of and demand for crude oil, NGLs and natural gas as well as the ongoing COVID-19 pandemic and ~~the~~its economic effects ~~of the pandemic~~, could reduce forecasted 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 ~~June~~September 30, 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.

June 30, 2021	Commodity Contracts				Gas Imbalances (1)
September 30, 2021	Commodity Contracts				Gas Imbalances (1)
	Assets		Liabilities		Assets (2)		Liabilities (3)
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	—	$	11	$	—	$	—
Significant other observable inputs (Level 2)	43		2430		1423		1126
Total fair value	43		3541		1423		1126
Netting adjustments	(43)		(43)		—		—
Total	$	—	$	3138	$	1423	$	1126


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	$	—	$	—
Significant other observable inputs (Level 2)	17		7		23		16

Total fair value	19		21		23		16
Netting adjustments	(19)		(19)		—		—
Total	$	—	$	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 ~~June~~September 30, 2021 and December 31, 2020.

(2)Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $143 million and $19 million at ~~June~~September 30, 2021 and December 31, 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 $32 million and $3 million at ~~June~~September 30, 2021 and December 31, 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:

	Six Months Ended June 30,
	Nine Months Ended September 30,
	2021		2020
	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest and debt AFUDC	$	81112	$	96129
Income taxes, net of refunds	(1)		1
Non-cash transactions:
Accounts payable related to capital expenditures	613		89
Lease liabilities related to derecognition of right-of-use assets	—(1)		(5)
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)	—		(3)

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(13) Related Party Transactions

The Partnership’s revenues from affiliated companies accounted for 65% and 76% of total revenues during the ~~six~~nine months ended ~~June~~September 30, 2021 and 2020, 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 June 30,				Six Months EndedJune 30,
	Three Months Ended September 30,				Nine Months EndedSeptember 30,
	2021		2020		2021		2020
	(In millions)
Gas transportation and storage service revenues — CenterPoint Energy	$	1615	$	2217	$	4358	$	5976
Natural gas product sales — CenterPoint Energy	5—		1—		5		1
Gas transportation and storage service revenues — OGE Energy	910		109		1929		1928
Natural gas product sales — OGE Energy	21		—4		3334		59
Total revenues — affiliated companies	$	3226	$	3330	$	~~100~~126	$	84114

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 June 30,				Six Months EndedJune 30,
	Three Months Ended September 30,				Nine Months EndedSeptember 30,
	2021		2020		2021		2020
	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	—	$	—	$	—	$	1
Cost of natural gas purchases — OGE Energy	1213		6		4356		1420
Total cost of natural gas purchases — affiliated companies	$	1213	$	6	$	4356	$	1521

Corporate services and seconded employees

The Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under services agreements for an initial term that ended on April 30, 2016. The services agreements automatically extend year-to-year at the end of the initial term, unless terminated by the Partnership with at least 90 days’ notice prior to the end of any extension. Additionally, the Partnership may terminate the services agreements at any time with 180 days’ notice, if approved by the Board of Enable GP. The Partnership reimburses CenterPoint Energy and OGE Energy for these services up to annual caps, which for 2021 are both less than $1 million.

As of ~~June~~September 30, 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 June 30,				Six Months EndedJune 30,
	Three Months Ended September 30,				Nine Months EndedSeptember 30,
	2021		2020		2021		2020
	(In millions)
Seconded Employee Costs — OGE Energy	$	34	$	5	$	711	$	813

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(14) Commitments and Contingencies

The Partnership is involved in legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Partnership regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Partnership does not expect the disposition of these matters to have a material adverse effect on its financial condition, results of operations or cash flows.

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 for deliveries to the Godley Plant in Johnson County, Texas. As of ~~June~~September 30, 2021, the Partnership estimates the remaining associated minimum volume commitment fee to be $~~159~~153 million. Minimum volume commitment fees are expected to be $104 million for the remainder of 2021, $23 million per year from 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. On June 1, 2021, FERC issued the Order Issuing Certificates and Approving Abandonment, which authorizes construction and operation of the Gulf Run Pipeline and transfer of certain existing EGT infrastructure to the Gulf Run Pipeline. On October 19, 2021, FERC issued the Notice to Proceed with Construction. The Partnership estimates the total cost toof ~~complete~~ the Gulf Run Pipeline project would be as much as $540 million, excluding AFUDC. The project is backed by a 20-year firm transportation service agreement. The Gulf Run Pipeline connects natural gas producing regions in the U.S., including the Haynesville, Marcellus, Utica and Barnett shales and the Mid-Continent region. The project is expected to be placed into service in late 2022.

(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 June 30,				Six Months EndedJune 30,
	Three Months Ended September 30,				Nine Months EndedSeptember 30,
	2021		2020		2021		2020
	(In millions)
Performance units	$	23	$	21	$	47	$	45
Phantom units	21		12		45		35
Total compensation expense	$	4	$	3	$	812	$	710

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


	2021
Number of units granted	1,453,897
Fair value of units granted	$	10.26
Expected distribution yield	12.90		%
Expected price volatility	100.00		%
Risk-free interest rate	0.27		%
Expected life of units (in years)	3

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


			2021
Phantom Units granted			1,371,001
Fair value of phantom units granted			$5.41 - $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 ~~June~~September 30, 2021 and changes during 2021 are shown in the following table.

	Performance Units				Phantom Units		~~Phantom Units~~
	Numberof Units		Weighted Average Grant-Date Fair Value, Per Unit		Numberof Units		Weighted Average Grant-Date Fair Value, Per Unit		~~Numberof Units~~		~~Weighted Average Grant-Date Fair Value, Per Unit~~
	(In millions, except unit data)
Units outstanding at December 31, 2020	1,765,508		$	13.10	1,790,845		$	10.29	~~1,790,845~~		$	~~10.29~~
Granted (1)	1,453,897		10.26		1,371,001		6.86		~~1,371,001~~		~~6.86~~
Vested (2)	(~~389~~398,~~817~~614)		17.70		(485,662)		13.08		~~(469,488)~~		~~13.07~~
Forfeited	(45,945)		9.94		(139,975)		8.52		~~(119,851)~~		~~8.51~~
Units outstanding at June 30, 2021	2,783,643		$	11.02					2,572,507		$	8.03
Units outstanding at September 30, 2021	2,774,846		$	11.00	2,536,209		$	7.99
Aggregate intrinsic value of units outstanding at June 30, 2021	$	25							$	23
Aggregate intrinsic value of units outstanding at September 30, 2021	$	23			$	21

_____________________

(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 ~~June~~September 30, 2021 include ~~389~~398,~~817~~614 units from the 2018 annual grant, which were approved by the Board of Directors in 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, 2018 through December 31, 2020, no performance units vested.

Unrecognized Compensation Cost

The following table summarizes the Partnership’s unrecognized compensation cost for its non-vested performance units and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized.

	June 30, 2021
	September 30, 2021
	Unrecognized Compensation Cost (In millions)		Weighted Average Period for Recognition (In years)
Performance Units	$	1916	21.0076
Phantom Units	1210		1.8461
Total	$	3126

As of ~~June~~September 30, 2021, there were 3,~~118~~151,~~170~~858 units available for issuance under the long-term incentive plan.

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(16) Reportable Segments

The Partnership’s determination of reportable segments considers the strategic operating units under which it manages sales, allocates resources and assesses performance of various products and services to customers in differing regulatory environments. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies excerpt in the Partnership’s audited 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 two reportable segments: (i) gathering and processing and (ii) transportation and storage. Our gathering and processing segment primarily provides natural gas gathering and 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.

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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.

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Financial data for reportable segments are as follows:

Three Months Ended June 30, 2021	Gathering andProcessing		Transportation (1)and Storage		Eliminations		Total
Three Months Ended September 30, 2021	Gathering andProcessing		Transportation (1)and Storage		Eliminations		Total
	(In millions)
Product sales	$	~~461~~625	$	~~135~~157	$	(~~136~~159)	$	~~460~~623
Service revenues	~~212~~214		~~118~~122		(3)		~~327~~333
Total Revenues	~~673~~839		~~253~~279		(~~139~~162)		~~787~~956
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	~~437~~571		~~128~~154		(~~139~~160)		~~426~~565
Operation and maintenance, General and administrative	7377		4443		(1)		~~116~~119
Depreciation and amortization	74		2930		—		~~103~~104
Taxes other than income tax	1110		76		—		1816
Operating income	$	78107	$	4546	$	(1)	$	~~124~~152
Total Assets	$	10,~~824~~953	$	56,~~917~~130	$	(45,~~982~~303)	$	11,~~759~~780
Capital expenditures (excluding equity AFUDC)	$	2027	$	5126	$	—	$	7153
Three Months Ended June 30, 2020	Gathering andProcessing		Transportation (1)and Storage		Eliminations		Total
Three Months Ended September 30, 2020	Gathering andProcessing		Transportation (1)and Storage		Eliminations		Total
	(In millions)
Product sales	$	~~193~~271	$	5979	$	(5670)	$	~~196~~280
Service revenues	~~198~~192		~~124~~126		(32)		~~319~~316
Total Revenues	~~391~~463		~~183~~205		(5972)		~~515~~596
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	~~176~~244		5978		(5872)		~~177~~250
Operation and maintenance, General and administrative	9277		4547		~~(1)~~—		~~136~~124
Depreciation and amortization	7475		3130		—		105
Taxes other than income tax	1110		67		—		17
Operating income	$	3857	$	4243	$	—	$	80100
Total assets as of December 31, 2020	$	10,830	$	5,729	$	(4,830)	$	11,729
Capital expenditures (excluding equity AFUDC)	$	2421	$	2429	$	—	$	4850

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Six Months Ended June 30, 2021	Gathering andProcessing		Transportation (1)and Storage		Eliminations		Total
Nine Months Ended September 30, 2021	Gathering andProcessing		Transportation (1)and Storage		Eliminations		Total
	(In millions)
Product sales	$	~~889~~1,514	$	~~467~~624	$	(~~269~~428)	$	1,~~087~~710
Service revenues	~~408~~622		~~268~~390		(69)		~~670~~1,003
Total Revenues	12,~~297~~136		~~735~~1,014		(~~275~~437)		12,~~757~~713
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	~~835~~1,406		~~385~~539		(~~275~~435)		~~945~~1,510
Operation and maintenance, General and administrative	~~152~~229		86129		(12)		~~237~~356
Depreciation and amortization	~~148~~222		6191		—		~~209~~313
Taxes other than income tax	2232		1420		—		3652
Operating income	$	~~140~~247	$	~~189~~235	$	1—	$	~~330~~482
Total Assets	$	10,~~824~~953	$	56,~~917~~130	$	(45,~~982~~303)	$	11,~~759~~780
Capital expenditures (excluding equity AFUDC)	$	4168	$	~~110~~136	$	—	$	~~151~~204
Six Months Ended June 30, 2020	Gathering andProcessing		Transportation (1)and Storage		Eliminations		Total
Nine Months Ended September 30, 2020	Gathering andProcessing		Transportation (1)and Storage		Eliminations		Total
	(In millions)
Product sales	$	~~468~~739	$	~~134~~213	$	(~~118~~188)	$	~~484~~764
Service revenues	~~400~~592		~~283~~409		(46)		~~679~~995
Total Revenues	~~868~~1,331		~~417~~622		(~~122~~194)		1,~~163~~759
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	~~387~~631		~~137~~215		(~~121~~193)		~~403~~653
Operation and maintenance, General and administrative	~~173~~250		90137		(1)		~~262~~386
Depreciation and amortization	~~148~~223		6191		—		~~209~~314
Impairments of property, plant and equipment and goodwill	28		—		—		28
Taxes other than income tax	2232		1320		—		3552
Operating income	$	~~110~~167	$	~~116~~159	$	—	$	~~226~~326
Total assets as of December 31, 2020	$	10,830	$	5,729	$	(4,830)	$	11,729
Capital expenditures (excluding equity AFUDC)	$	5879	$	4473	$	—	$	~~102~~152

_____________________

(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 ~~six~~nine months ended ~~June~~September 30, 2021 and 2020.

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

The following discussion and analysis should be read in conjunction with our unaudited Condensed Consolidated Financial Statements and the related notes included herein and our audited Consolidated Financial Statements for the year ended December 31, 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~~its 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.

Overview

Enable Midstream Partners, LP owns, operates and develops midstream energy infrastructure assets strategically located to serve our customers. We are traded on the 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.

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 ~~June~~September 30, 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

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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

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 ~~June~~September 30, 2021, we had a working capital deficit of $~~842~~763 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 ~~June~~September 30, 2021 as well as $~~171~~50 million of commercial paper outstanding as of ~~June~~September 30, 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.

	Six Months Ended June 30,
	Nine Months Ended September 30,
	2021		2020
	(In millions)
Net cash provided by operating activities	$	~~413~~678	$	~~311~~543
Net cash used in investing activities	(~~143~~198)		(73120)
Net cash used in financing activities	(~~245~~447)		(~~231~~409)

Operating Activities

The increase of $~~102~~135 million, or 3325%, in net cash provided by operating activities for the ~~six~~nine months ended ~~June~~September 30, 2021 as compared to the ~~six~~nine months ended ~~June~~September 30, 2020 was primarily driven by an increase in net income of $~~104~~383 million and an increase of $4222 million in the timing of cash receipts and disbursements and changes in other working capital assets and liabilities, partially offset by a decrease in adjustments for non-cash items of $44270 million.

Investing Activities

The increase of $7078 million, or 9665%, in net cash used in investing activities for the ~~six~~nine months ended ~~June~~September 30, 2021 as compared to the ~~six~~nine months ended ~~June~~September 30, 2020 was primarily due to higher capital expenditures of $4952 million, a decrease in return of investment in equity method affiliate of $59 million and a decrease in proceeds from sale of assets of $16 million.

Financing Activities

Net cash used in financing activities increased $1438 million, or 69%, for the ~~six~~nine months ended ~~June~~September 30, 2021 as compared to the ~~six~~nine months ended ~~June~~September 30, 2020. Our primary financing activities consist of the following:

	Six Months Ended June 30,
	Nine Months Ended September 30,
	2021		2020
	(In millions)
Decrease in short-term debt	$	(79)	$	(125)
Increase (decrease) in short-term debt	$	(200)	$	179
Repayment of EOIT Senior Notes	—		(250)
Repurchase of 2029 Senior Notes and 2044 Senior Notes	—		(17)
Net proceeds from Revolving Credit Facility	—		400
Distributions	(245)		(320)
Distributions	(164)		(237)
Cash paid for employee equity-based compensation	(2)		(1)
Cash paid for employee equity-based compensation	(2)		(2)

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Distributions

On ~~July~~October 3026, 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 ~~June~~September 30, 2021. The distributions will be paid ~~August~~November 2417, 2021 to unitholders of record as of the close of business on ~~August~~November 128, 2021. Additionally, the Board of Directors declared a quarterly cash distribution of $0.~~5439~~5403 on the Partnership’s outstanding Series A Preferred Units. The distributions will be paid ~~August~~November 1312, 2021 to unitholders of record as of the close of business on ~~July~~October 3026, 2021.

Trends Affecting Liquidity and Capital Resources

Borrowing Capacity

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. As of ~~June~~September 30, 2021, our available borrowing capacity under our Revolving Credit Facility was approximately $1.25 billion 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 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~~and ~~transaction is subject to~~ the ~~receipt of the required approvals from the~~ holders of a majority of our common units,. The transaction remains subject to 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, as amended (File No. 333-254477), initially filed by Energy Transfer on March 19, 2021 (the “Energy Transfer Registration Statement”), 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.

On May 12, 2021, the Partnership and Energy Transfer each received a request for additional information and documentary material (the “Second Request”) from the FTC in connection with the FTC’s review of the transactions contemplated by the Merger Agreement under the HSR Act. The effect of the Second Request is to extend the waiting period imposed by the HSR Act until 30 days after the Partnership and Energy Transfer have certified substantial compliance with the Second Request, unless that period is extended voluntarily by the parties or terminated sooner by the FTC.

The Merger is anticipated to close in the ~~second~~fourth ~~half~~quarter of 2021. We cannot provide any assurance that the combination will be completed on the terms or timeline currently contemplated, or at all. The above includes a summary of the material terms of the Merger, which is qualified in its entirety by reference to the Energy Transfer Registration Statement.

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COVID-19 Pandemic

Throughout the COVID-19 pandemic, 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. In compliance with Center for Disease Control guidance, we implemented strategies to protect the health and safety of our workers, including virtual symptom screening, social distancing, wearing masks, limiting non-essential travel, and, where possible, utilizing remote working. In April 2021, we began returning additional employees to the workplace who had been working remotely. We will continue to monitor for the resurgence of COVID-19 in our workplaces and in the communities where our employees are located and adjust our strategies accordingly.

Commodity Price Environment

Our business is impacted by commodity prices, which have continued to experience significant volatility. Commodity prices impact the drilling and production of natural gas and crude oil in the areas served by our systems, and the volumes on our systems are impacted by the amount of drilling and production in the 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 commodity prices, drilling and production on the 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 our Annual Report.

We have attempted to mitigate the impact of commodity prices on our business by entering into hedges, focusing on contracting fee-based business and converting existing commodity-based contracts to fee-based contracts. For additional information regarding our commodity price risk, see Item 7A. “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk” in our Annual Report.

During the ~~six~~nine months ended ~~June~~September 30, 2021 as compared to the ~~six~~nine months ended ~~June~~September 30, 2020, our revenues and gross margin increased. These increases resulted, ~~primarily~~in part, from the impact of the February 2021 Winter Storm Uri on our financial results for the first quarter of 2021. 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. These increases resulted secondarily from the impact of the increases in commodity prices on our financial results for the second quarter of 2021. Low inventories of natural gas, NGLs and crude oil, and lower production of natural gas and crude oil, resulted in higher commodity prices, which increased our proceeds from product sales. The results of our most recent nine month period may not be indicative of our future results because of the temporary effects of the winter storm and the continuing uncertainty surrounding future levels of production and prices of natural gas and crude oil. For more information on our results, see “—Financial Results” below.

During the six months ended June 30, 2021 as compared to the six months ended June 30, 2020, our natural gas gathered volumes, processed volumes, transported volumes, and crude oil and condensate gathered volumes decreased. These decreases resulted primarily from reductions in the exploration and production of natural gas and crude oil, which resulted in a corresponding decrease in demand for midstream services. The reductions in exploration and production resulted from the combination of oversupply conditions in late 2019, demand decreases due to the COVID-19 pandemic in 2020 and temporary supply disruptions due to Winter Storm Uri in 2021. The results for our most recent period may not be indicative of our future results because of the continuing uncertainty surrounding future levels of exploration and production of natural gas and crude oil, and the demand for midstream services to gather and process natural gas and to move natural gas, NGLs and crude oil to markets. For more information on our results, see “—Financial Results” below.

Recent Developments

Dakota Access Pipeline

On July 6, 2020, the federal district court for the District of Columbia (the “District Court”) issued an order vacating an easement, that was issued by the Corps and which allowed Dakota Access Pipeline to cross the Missouri River, pending the completion of an environmental impact statement (EIS) for the pipeline. On May 21, 2021, the District Court denied the request for an injunction that would have shut down the pipeline during the pendency of the environmental review. On June 22, 2021, the District Court dismissed without prejudice all outstanding claims in the matter. On September 20, 2021, Dakota Access Pipeline filed a petition for writ of certiorari asking the U.S. Supreme Court to review whether an EIS was required. The EIS is anticipated to be completed in March 2022. Following the completion of the EIS, the Corps will make a new decision about whether to grant the pipeline an easement to cross the Missouri River, unless the writ of certiorari for review by the U.S. Supreme Court is granted and the appeal of the order to conduct the EIS is successful. We are unable to predict the outcome of the appeal, the EIS or the new easement decision. In addition, either the EIS or the new easement decision may subsequently be subject to challenge in court.

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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 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 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. We are unable to predict whether any such pipeline will be 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.

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Five Nations Reservations

On July 9, 2020, the U.S. Supreme Court ruled in McGirt v. Oklahoma (“McGirt”) 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.

State district courts in Oklahoma, applying the analysis in the U.S. Supreme Court’s ruling regarding the Muscogee (Creek) Nation, have ruled that the Cherokee, Chickasaw, Seminole and Choctaw reservations likewise have not been disestablished. On October 1, 2020, the EPA granted approval to the State of Oklahoma under Section 10211(a) of the Safe, Accountable, 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, subject to certain 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 in McGirt. 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.~~

Separately, in 2021, the U.S. Department of the Interior (“DOI”) subsequently used the ruling in McGirt to find that Oklahoma could not keep jurisdiction over surface coal mining in the Muscogee (Creek) Nation’s lands. The State of Oklahoma

has petitioned the U.S. Supreme Court to overturn this determination and find that McGirt either is limited to federal criminal matters or was incorrectly decided. Several other suits have been filed in state and federal courts regarding the appropriate scope of McGirt, including a stayed proceeding before the Oklahoma Supreme Court regarding the Oklahoma Corporation Commission’s authority to issue drilling permits on the Muscogee (Creek) reservations. At this time, we cannot predict how these issues may ultimately be resolved.

Suspension of Leases and Permits on Federal Lands

On January 20, 2021, the 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. On June 15, 2021, the U.S. District Court for the Western District of Louisiana issued a preliminary injunction blocking the Biden administration from continuing to enforce its moratorium on new oil and gas leases and permits on federal lands. The Biden administration isappealed ~~expected~~the ruling on August 16, 2021 to ~~appeal~~the U.S. Court of Appeals for the ~~ruling~~Fifth Circuit. The same day, a dozen energy industry trade groups lead by the American Petroleum Institute filed an additional lawsuit U.S. District Court for the Western District of Louisiana challenging the moratorium. 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

PHMSA is expected to issue several rules in 2021 or 2022, 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 Safety of Gas Gathering Pipelines rule. Other agencies, such as the EPA, are also expected to issue new regulations that may impact our operations. While we cannot predict 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 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.

FERC Update

On February 18, 2021, FERC issued a renewed Notice of Inquiry (NOI) seeking input on potential revisions to its current policy statement on the certification of new natural gas transmission facilities. The NOI supplements a 2018 NOI issued by FERC on the same topic. Comments on the NOI were due on May 26, 2021. We are unable to predict what, if any, changes may be proposed as a result of the NOI that would affect our transportation and storage segment or when such proposals, if any, might become effective.

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Financial Results

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

Three Months Ended June 30, 2021	Gathering andProcessing		Transportationand Storage		Eliminations		EnableMidstreamPartners, LP
Three Months Ended September 30, 2021	Gathering andProcessing		Transportationand Storage		Eliminations		EnableMidstreamPartners, LP
	(In millions)
Product sales	$	~~461~~625	$	~~135~~157	$	(~~136~~159)	$	~~460~~623
Service revenues	~~212~~214		~~118~~122		(3)		~~327~~333
Total Revenues	~~673~~839		~~253~~279		(~~139~~162)		~~787~~956
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	~~437~~571		~~128~~154		(~~139~~160)		~~426~~565
Gross margin (1)	~~236~~268		125		—(2)		~~361~~391
Operation and maintenance, General and administrative	7377		4443		(1)		~~116~~119
Depreciation and amortization	74		2930		—		~~103~~104
Taxes other than income tax	1110		76		—		1816
Operating income	$	78107	$	4546	$	(1)	$	~~124~~152
Equity in earnings of equity method affiliate, net	$	—	$	—	$	—	$	—

Three Months Ended June 30, 2020	Gathering andProcessing		Transportationand Storage		Eliminations		EnableMidstreamPartners, LP
Three Months Ended September 30, 2020	Gathering andProcessing		Transportationand Storage		Eliminations		EnableMidstreamPartners, LP
	(In millions)
Product sales	$	~~193~~271	$	5979	$	(5670)	$	~~196~~280
Service revenues	~~198~~192		~~124~~126		(32)		~~319~~316
Total Revenues	~~391~~463		~~183~~205		(5972)		~~515~~596
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	~~176~~244		5978		(5872)		~~177~~250
Gross margin (1)	~~215~~219		~~124~~127		~~(1)~~—		~~338~~346
Operation and maintenance, General and administrative	9277		4547		~~(1)~~—		~~136~~124
Depreciation and amortization	7475		3130		—		105
Taxes other than income tax	1110		67		—		17
Operating income	$	3857	$	4243	$	—	$	80100
Equity in earnings of equity method affiliate	$	—	$	5	$	—	$	5

Six Months Ended June 30, 2021

Gathering andProcessing

Transportationand Storage

Eliminations

EnableMidstreamPartners, LP

Nine Months Ended September 30, 2021

Gathering andProcessing

Transportationand Storage

Eliminations

EnableMidstreamPartners, LP

(In millions)

Product sales

~~889~~1,514

~~467~~624

(~~269~~428)

1,~~087~~710

Service revenues

~~408~~622

~~268~~390

(69)

~~670~~1,003

Total Revenues

12,~~297~~136

~~735~~1,014

(~~275~~437)

12,~~757~~713

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

~~835~~1,406

~~385~~539

(~~275~~435)

~~945~~1,510

Gross margin (1)

~~462~~730

~~350~~475

—(2)

~~812~~1,203

Operation and maintenance, General and administrative

~~152~~229

86129

(12)

~~237~~356

Depreciation and amortization

~~148~~222

6191

—

~~209~~313

Taxes other than income tax

2232

1420

—

3652

Operating income

~~140~~247

~~189~~235

1—

~~330~~482

Equity in earnings of equity method affiliate, net

—

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Six Months Ended June 30, 2020

Gathering andProcessing

Transportationand Storage

Eliminations

EnableMidstreamPartners, LP

Nine Months Ended September 30, 2020

Gathering andProcessing

Transportationand Storage

Eliminations

EnableMidstreamPartners, LP

(In millions)

Product sales

~~468~~739

~~134~~213

(~~118~~188)

~~484~~764

Service revenues

~~400~~592

~~283~~409

(46)

~~679~~995

Total Revenues

~~868~~1,331

~~417~~622

(~~122~~194)

1,~~163~~759

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

~~387~~631

~~137~~215

(~~121~~193)

~~403~~653

Gross margin (1)

~~481~~700

~~280~~407

(1)

~~760~~1,106

Operation and maintenance, General and administrative

~~173~~250

90137

(1)

~~262~~386

Depreciation and amortization

~~148~~223

6191

—

~~209~~314

Impairments of property, plant and equipment and goodwill

—

Taxes other than income tax

2232

1320

—

3552

Operating income

~~110~~167

~~116~~159

—

~~226~~326

Equity in earnings of equity method affiliate

—

_____________________

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

	Three Months Ended June 30,		Six Months EndedJune 30,
	Three Months Ended September 30,		Nine Months EndedSeptember 30,
	2021	2020	2021	2020
Operating Data:
Natural gas gathered volumes—TBtu	~~399~~402	~~377~~374	~~767~~1,169	~~788~~1,164
Natural gas gathered volumes—TBtu/d	4.3937	4.1407	4.2428	4.3325
Natural gas processed volumes—TBtu (1)	~~200~~208	~~185~~190	~~385~~593	~~408~~597
Natural gas processed volumes—TBtu/d (1)	2.2026	2.0406	2.1317	2.2418
NGLs produced—MBbl/d (1)(2)	~~145~~141.6146	~~112~~133.7811	~~132~~135.3341	~~116~~122.8229
NGLs sold—MBbl/d (2)(3)	~~147~~143.6232	~~122~~138.9955	~~133~~137.8202	~~122~~127.1566
Condensate sold—MBbl/d	65.7680	5.6858	6.7744	6.9650
Crude oil and condensate gathered volumes—MBbl/d	~~110~~97.987	84138.6802	~~112~~107.1730	~~112~~121.9738
Transported volumes—TBtu	~~499~~491	~~495~~440	1,~~048~~539	1,~~092~~532
Transported volumes—TBtu/d	5.4433	54.4078	5.7762	5.9858
Interstate firm contracted capacity—Bcf/d	5.7362	5.7873	65.1396	6.1300
Intrastate average deliveries—TBtu/d	1.5769	1.6774	1.6164	1.8783

_____________________

(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 June 30,		Six Months EndedJune 30,
	Three Months Ended September 30,		Nine Months EndedSeptember 30,
	2021	2020	2021	2020
Anadarko
Gathered volumes—TBtu/d	2.1418	1.8994	2.0710	2.0904
Natural gas processed volumes—TBtu/d (1)	1.9398	1.7376	1.8689	1.9085
NGLs produced—MBbl/d (1)(2)	~~132~~127.7771	~~100~~120.3480	~~120~~122.4791	~~103~~109.4629
Crude oil and condensate gathered volumes—MBbl/d	7970.9736	61104.4093	8076.3699	8793.9465
Arkoma
Gathered volumes—TBtu/d	0.40	0.3941	0.3940	0.4142
Natural gas processed volumes—TBtu/d (1)	0.07	0.08	0.07	0.08
NGLs produced—MBbl/d (1)(2)	4.4876	43.0594	34.9925	3.9796
Ark-La-Tex
Gathered volumes—TBtu/d	1.8579	1.8672	1.78	1.8379
Natural gas processed volumes—TBtu/d	0.2021	0.2322	0.2021	0.2625
NGLs produced—MBbl/d (2)	8.3699	8.3937	78.8725	9.3904
Williston
Crude oil gathered volumes—MBbl/d	3127.0135	2333.2809	3130.8131	2527.0373

_____________________

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

(2)Excludes condensate.

Gathering and Processing

Three months ended ~~June~~September 30, 2021 compared to three months ended ~~June~~September 30, 2020. Our gathering and processing segment reported operating income of $78107 million for the three months ended ~~June~~September 30, 2021 compared to operating income of $3857 million for the three months ended ~~June~~September 30, 2020. The difference of $4050 million in operating income between periods was primarily due to a $2149 million increase in gross margin and a $191 million decrease in ~~operation~~depreciation and ~~maintenance and general and administrative expenses~~amortization.

Our gathering and processing segment revenues increased $~~282~~376 million. The increase was primarily due to the following:

Product Sales:

•revenues from NGL sales increased $~~246~~296 million primarily due to an increase in the average realized sales price from higher average market prices for NGL products combined with higher recoveries of ethane and higher processed volumes ~~and~~,

•revenues from natural gas sales increased $4470 million due to higher average sales prices. and

•changes in the fair value of natural gas, condensate and NGL derivatives increased $7 million.

These increases were partially offset by:

•higher realized losses on natural gas, condensate and NGL derivatives of $1619 million ~~and~~.

•changes in the fair value of natural gas, condensate and NGL derivatives decreased $6 million.

Service Revenues:

•processing service revenues increased $921 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 and ~~a decrease in the recognition of certain annual minimum processing fees and~~

•~~crude~~natural ~~oil,~~gas ~~condensate and produced water~~ gathering ~~revenue,~~revenues ~~which~~ increased $6 million ~~primarily~~ due to anhigher ~~increase~~volumes gathered in ~~gathered~~the ~~crude~~Anadarko ~~oil~~Basin, ~~and~~partially ~~condensate~~offset ~~volumes~~by lower average rates on certain contracts.

These increases were partially offset by ~~natural~~crude ~~gas~~oil, condensate and produced water gathering ~~revenues~~revenue, which decreased $15 million primarily due to ~~lower~~a ~~volumes~~decrease in gathered ~~under~~crude ~~fee-based~~oil ~~arrangements~~and condensate volumes from lower producer activity.

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Our gathering and processing segment gross margin increased $2149 million. The increase was primarily due to the following:

•revenues from NGL sales, less the cost of NGLs increased $4742 million primarily due to an increase in the average realized sales price from higher average market prices for NGL products combined with higher recoveries of ethane and higher processed volumes,

•processing service fees increased $921 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 ~~and a decrease in the recognition of certain annual minimum processing fees and~~,

•~~crude~~changes ~~oil~~in the fair value of natural gas, condensate and ~~produced~~NGL ~~water~~derivatives ~~gathering revenues~~ increased $67 million ~~primarily due to an increase in gathered crude oil~~ and ~~condensate volumes.~~

•natural gas gathering fees increased $6 million due to higher volumes gathered in the Anadarko Basin, partially offset by lower average rates on certain contracts.

These increases were partially offset by:

•~~revenues~~higher ~~from~~realized losses on natural gas, ~~sales~~condensate ~~less~~and ~~the~~NGL ~~cost~~derivatives of ~~natural gas decreased approximately~~ $1819 million ~~due to higher natural gas purchase costs~~,

•~~higher~~crude ~~realized losses on natural gas~~oil, condensate and ~~NGL~~produced ~~derivatives~~water ofgathering revenues decreased $165 million, primarily due to a decrease in gathered crude oil and condensate volumes from lower producer activity and

•~~changes~~revenues infrom ~~the fair value of~~ natural gas sales, ~~condensate~~less ~~and~~the ~~NGL~~cost ~~derivatives~~of natural gas decreased approximately $63 million ~~and~~due to higher natural gas purchase costs.

~~•natural~~Our ~~gas~~ gathering ~~fees~~and ~~decreased~~processing segment operation and maintenance and general and administrative expenses remained flat. The primary activity resulted in a $4 million decrease in payroll-related costs as a result of lower headcount and a $1 million decrease due to ~~lower~~insurance ~~volumes~~proceeds, ~~gathered~~partially ~~under~~offset ~~fee-based~~by ~~arrangements~~remediation costs associated with our Williston Basin operations. These decreases were offset by a $5 million increase in professional services primarily due to transaction costs related to the pending merger with Energy Transfer.

Our gathering and processing segment ~~operation~~depreciation and ~~maintenance~~amortization ~~and general and administrative expenses~~ decreased $191 million. ~~The decrease was~~ primarily due to aretirements ~~$20 million loss on retirement~~ of angeneral ~~Ark-La-Tex~~plant ~~gathering system in 2020, with minor activity in 2021, a $3 million decrease in payroll-related costs as a result of lower headcount, and a $2 million decrease in field equipment rentals~~assets. These decreases were partially offset by a $4 million increase in professional services primarily due to transaction costs related to the pending merger with Energy Transfer and a $1 million increase due to lower capitalized overhead costs.

~~Six~~Nine months ended ~~June~~September 30, 2021 compared to ~~six~~nine months ended ~~June~~September 30, 2020. Our gathering and processing segment reported operating income of $~~140~~247 million for the ~~six~~nine months ended ~~June~~September 30, 2021 compared to operating income of $~~110~~167 million for the ~~six~~nine months ended ~~June~~September 30, 2020. The difference of $3080 million in operating income between periods was primarily due to a $30 million increase in gross margin, $28 million of property, plant and equipment and goodwill impairments recognized in 2020 with no comparable item in 2021, and a $21 million decrease in operation and maintenance and general and administrative expenses~~, partially offset by a $19 million decrease in gross margin~~.

Our gathering and processing segment revenues increased $~~429~~805 million. The increase was primarily due to the following:

Product Sales:

•revenues from NGL sales increased $~~376~~672 million primarily due to an increase in the average realized sales price from higher average market prices for NGL products combined with higher recoveries of ethane, ~~partially offset by lower processed volumes~~ and

•revenues from natural gas sales increased $~~100~~170 million due to higher average sales prices, partially offset by lower sales volumes.

These increases were partially offset by:

•higher realized losses on natural gas, condensate and NGL derivatives of $3049 million and

•changes in the fair value of natural gas, condensate and NGL derivatives decreased $2518 million.

Service Revenues:

~~•processing~~Processing service revenues increased $1233 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 and a decrease in the recognition of certain annual minimum processing fees. ~~and~~

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

~~These increases were partially offset by~~ •natural gas gathering revenues, which decreased $93 million due to lower ~~gathered~~average ~~volumes,~~rates ~~inclusive~~on ofcertain contracts and volume curtailments and production freeze-offs related to Winter Storm Uri, partially offset by higher assessed producer imbalance penalties. and

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~~Our~~•crude ~~gathering~~oil, condensate and ~~processing~~produced ~~segment~~water ~~gross~~gathering ~~margin~~revenue ~~decreased~~remained ~~$19~~flat, ~~million.~~due ~~The~~to an increase in gathered crude oil volumes in the Williston Basin, offset by a decrease ~~was~~in gathered crude oil and condensate volumes in the Anadarko Basin primarily due to ~~the~~lower ~~following:~~producer activity.

~~•higher~~Our ~~realized~~gathering ~~losses~~and onprocessing ~~natural~~segment ~~gas,~~gross ~~condensate~~margin ~~and~~increased ~~NGL derivatives of~~ $30 million,. The increase was primarily due to the following:

•revenues from ~~natural~~NGL ~~gas~~ sales, less the cost of ~~natural~~NGLs ~~gas~~increased ~~decreased approximately~~ $2898 million primarily due to an increase in the average realized sales price from higher ~~natural~~average ~~gas~~market ~~purchase~~prices ~~costs,~~for ~~inclusive~~NGL ofproducts ~~purchase~~combined ~~costs~~with ~~related~~higher torecoveries ~~Winter~~of ~~Storm~~ethane ~~Uri,~~and

•~~changes~~processing inservice ~~the~~fees ~~fair~~increased ~~value~~$33 ofmillion ~~natural~~due ~~gas~~to higher consideration received from percent-of-proceeds, ~~condensate~~percent-of-liquids and ~~NGL~~keep-whole ~~derivatives~~processing ~~decreased~~arrangements ~~$25~~due ~~million~~to higher average market prices, partially offset by lower processed volumes under fee-based arrangements and a decrease in the recognition of certain annual minimum processing fees.

~~•natural~~These ~~gas~~increases ~~gathering~~were ~~fees decreased $9 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.~~:

~~These~~•higher ~~decreases~~realized ~~were~~losses ~~partially~~on ~~offset~~natural ~~by:~~gas, condensate and NGL derivatives of $49 million,

•revenues from ~~NGL~~natural gas sales, less the cost of ~~NGLs~~natural ~~increased~~gas decreased approximately $5631 million ~~primarily~~ due to ~~an increase in the average realized sales price from~~ higher ~~average~~natural ~~market~~gas ~~prices~~purchase ~~for~~costs, ~~NGL~~inclusive ~~products combined with higher recoveries~~ of ~~ethane,~~purchase ~~partially~~costs ~~offset~~related byto ~~lower~~Winter ~~processed~~Storm ~~volumes~~Uri,

•~~processing~~changes ~~service~~in ~~fees~~the ~~increased~~fair ~~$12~~value ~~million due to higher consideration received from percent-~~of~~-proceeds,~~ ~~percent-of-liquids~~natural ~~and keep-whole processing arrangements due to higher average market prices~~gas, ~~partially~~condensate ~~offset by lower processed volumes under fee-based arrangements~~ and aNGL ~~decrease~~derivatives indecreased ~~the~~$18 ~~recognition of certain annual minimum processing fees and~~million,

•~~crude~~natural ~~oil,~~gas ~~condensate and produced water~~ gathering ~~revenues~~fees ~~increased~~decreased $5 3 million ~~primarily~~ due to anlower ~~increase~~average inrates ~~gathered~~on ~~crude~~certain ~~oil~~contracts ~~volumes~~and involume ~~the~~curtailments ~~Williston~~and ~~Basin,~~production ~~partially~~freeze-offs ~~offset~~related byto aWinter ~~decrease~~Storm inUri, ~~gathered~~partially ~~crude~~offset ~~oil~~by ~~and~~higher ~~condensate~~assessed ~~volumes~~producer inimbalance ~~the~~penalties ~~Anadarko Basin.~~and

~~Our~~•crude ~~gathering~~oil, ~~and~~condensate ~~processing segment operation~~ and ~~maintenance~~produced ~~and~~water ~~general~~gathering ~~and~~revenue ~~administrative~~remained ~~expenses~~flat, ~~decreased $21 million. The decrease was primarily~~ due to ~~a $20 million loss on retirement of~~ an ~~Ark-La-Tex~~increase ~~gathering system~~ in ~~2020,~~gathered ~~with~~crude ~~minor~~oil ~~activity~~volumes in ~~2021,~~the aWilliston ~~$9 million decrease in payroll-related costs as a result of lower headcount~~Basin, ~~a $5 million decrease in field equipment rentals. These decreases were partially~~ offset by a ~~$11 million~~decrease ~~increase~~ in ~~professional~~gathered ~~services~~crude ~~primarily~~oil ~~due~~and tocondensate ~~transaction~~volumes ~~costs~~in ~~related to~~ the ~~pending~~Anadarko ~~merger~~Basin ~~with~~primarily ~~Energy Transfer and a $2 million increase~~ due to lower ~~capitalized~~producer ~~overhead costs~~activity.

~~During~~Our ~~the~~gathering ~~six~~and ~~months~~processing ~~ended~~segment ~~June~~operation ~~30,~~and maintenance and general and administrative expenses decreased $21 million. The decrease was primarily due to a $20 million loss on retirement of an Ark-La-Tex gathering system in 2020, ~~our~~with ~~gathering~~minor ~~and~~activity ~~processing~~in ~~segment~~2021, ~~recognized~~a ~~impairments~~$13 million decrease in payroll-related costs as a result of ~~property~~lower headcount, ~~plant~~a ~~and~~$5 million decrease in field equipment rentals and ~~goodwill~~a of $282 million decrease due to insurance proceeds, partially offset by remediation costs associated with noour ~~impairment~~Williston ~~recognized~~Basin operations. These decreases were partially offset by a $16 million increase in ~~2021~~professional services primarily due to transaction costs related to the pending merger with Energy Transfer and a $2 million increase due to lower capitalized overhead costs.

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

During the nine months ended September 30, 2020, our gathering and processing segment recognized impairments of property, plant and equipment and goodwill of $28 million with no impairment recognized in 2021.

Transportation and Storage

Three months ended ~~June~~September 30, 2021 compared to three months ended ~~June~~September 30, 2020. Our transportation and storage segment reported operating income of $4546 million for the three months ended ~~June~~September 30, 2021 compared to operating income of $4243 million for the three months ended ~~June~~September 30, 2020. The difference of $3 million in operating income between periods was primarily due to a $14 million ~~increase in gross margin, a $1 million~~ decrease in operation and maintenance and general and administrative expenses, and a $21 million decrease in ~~depreciation~~taxes ~~and~~other ~~amortization~~than income tax, partially offset by a $12 million ~~increase~~decrease in ~~taxes~~gross ~~other than income tax~~margin.

Our transportation and storage segment revenues increased $7074 million. The increase was primarily due to the following:

Product Sales:

•revenues from natural gas sales increased $7681 million primarily due to higher average sales prices ~~and sales volumes and~~,

•revenues from NGL sales increased $23 million due to higher average sales prices, partially offset by lower volumes. and

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

•These increases were partially offset by higher realized losses on natural gas derivatives of $17 million ~~and~~.

~~•changes in the fair value of natural gas derivatives, which decreased $1 million.~~45

Service Revenues:

•firm transportation and storage services decreased $6 million primarily due to interstate contract extensions at lower rates and terminations of certain intrastate firm transportation agreements.

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~~Our~~Service ~~transportation and storage segment gross margin increased $1 million. The increase was primarily due to the following~~Revenues:

•~~system~~volume-dependent ~~management~~transportation ~~activities~~and storage revenue increased $62 million primarily due to ~~higher~~an ~~average~~increase ~~natural~~in ~~gas~~interstate ~~sales~~transported ~~prices, less the cost of natural gas,~~volumes.

~~•revenues~~This ~~from~~increase ~~NGL~~was ~~sales,~~offset ~~less~~by ~~the~~firm ~~cost~~transportation ofand ~~NGLs~~storage ~~increased~~services, which decreased $26 million primarily due to aninterstate ~~increase~~contract inextensions ~~average~~at ~~NGL~~lower ~~prices~~rates and reductions in contracted capacity on certain intrastate firm transportation agreements.

•aOur ~~$1 million~~transportation ~~reduction~~and instorage ~~lower~~segment ofgross ~~cost~~margin ordecreased ~~net~~$2 million. ~~realizable~~The ~~value~~decrease ~~adjustments~~was ~~related~~primarily due to ~~natural~~the ~~gas storage inventories.~~following:

~~These~~•higher ~~increases~~realized ~~were~~losses ~~partially~~on ~~offset~~natural ~~by:~~gas derivatives of $7 million and

•firm transportation and storage services decreased $6 million primarily due to interstate contract extensions at lower rates and ~~terminations~~reductions ofin contracted capacity on certain intrastate firm transportation agreements,.

~~•higher~~These ~~realized~~decreases ~~losses~~were onpartially ~~natural~~offset ~~gas derivatives of $1 million and~~by:

•~~changes~~system inmanagement ~~the~~activities ~~fair~~increased ~~value of natural gas derivatives, which decreased~~ $15 million.,

~~Our~~•volume-dependent transportation and storage ~~segment~~revenue ~~operation~~increased ~~and maintenance and general and administrative expenses decreased~~ $12 million. ~~The decrease was~~ primarily ~~driven~~due byto aan ~~$3 million~~increase ~~decrease~~ in ~~payroll-related~~interstate ~~costs~~transported ~~as a result of lower headcount~~volumes, ~~partially offset by a $3 million increase in loss contingencies.~~

~~Our~~•a ~~transportation~~$2 million ~~and~~reduction ~~storage~~in ~~segment~~lower ~~depreciation~~of ~~and~~cost ~~amortization~~or ~~decreased~~net ~~$2 million~~realizable ~~primarily~~value ~~due~~adjustments related to ~~retirements~~natural ofgas ~~general~~storage ~~plant assets.~~inventories,

~~Our~~•revenues ~~transportation~~from ~~and~~NGL ~~storage~~sales, ~~segment~~less ~~taxes~~the ~~other~~cost ~~than~~of ~~income~~NGLs increased $1 million ~~primarily~~ due to ~~additional~~an ~~assets~~increase ~~placed~~ in ~~service.~~average NGL prices, partially offset by lower volumes and

~~Six~~•changes ~~months~~in ~~ended June 30, 2021 compared to six months ended June 30, 2020. Our transportation and storage segment reported operating income of $189 million for~~ the ~~six~~fair ~~months~~value ~~ended June 30, 2021 compared to operating income~~ of ~~$116~~natural ~~million~~gas ~~for the six months ended June 30~~derivatives, ~~2020.~~which ~~The~~increased ~~difference of~~ $73 million in operating income between periods was primarily due to a $70 million increase in gross margin and a $4 million decrease in operation and maintenance and general and administrative expenses, partially offset by a $1 million ~~increase in taxes other than income tax~~.

Our transportation and storage segment ~~revenues~~operation ~~increased~~and ~~$318~~maintenance and general and administrative expenses decreased $4 million. The ~~increase~~decrease was primarily driven by a $3 million decrease in payroll-related costs as a result of lower headcount and a $3 million decrease due to the ~~following:~~receipt of previously reserved amounts in allowance for doubtful accounts, partially offset by a $1 million increase due to a decrease in capitalized costs.

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

Nine months ended September 30, 2021 compared to nine months ended September 30, 2020. Our transportation and storage segment reported operating income of $235 million for the nine months ended September 30, 2021 compared to operating income of $159 million for the nine months ended September 30, 2020. The difference of $76 million in operating income between periods was primarily due to a $68 million increase in gross margin and a $8 million decrease in operation and maintenance and general and administrative expenses.

Our transportation and storage segment revenues increased $392 million. The increase was primarily due to the following:

Product Sales:

•revenues from natural gas sales increased $~~333~~414 million primarily due to higher average sales prices and sales volumes and

•revenues from NGL sales increased $36 million due to higher average sales prices, partially offset by lower volumes.

These increases were partially offset by:

•~~changes~~higher inrealized ~~the~~losses ~~fair~~on ~~value of~~ natural gas derivatives, ~~which~~of ~~decreased~~ $28 million and

•~~higher~~changes ~~realized~~in ~~losses~~the onfair value of natural gas derivatives, ofwhich decreased $1 million.

Service Revenues:

•volume-dependent transportation and storage revenues increased $68 million due to an increase in interstate transported volumes and assessed shipper imbalance penalties, partially offset by lower off-system intrastate transported volumes, 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.

This increase was partially offset by firm transportation and storage services which decreased $21 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 combined with interstate contract extensions at lower rates and terminations of certain intrastate firm transportation agreements.46

Our transportation and storage segment gross margin increased $70 million. The increase was primarily due to the following:

•system management activities increased $80 million primarily due to higher average natural gas sales prices, less the cost of natural gas,

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~~•volume-dependent~~This ~~transportation and storage revenues increased $6 million due to an~~ increase inwas ~~assessed shipper imbalance penalties,~~ partially offset by ~~lower~~firm ~~off-system~~transportation ~~intrastate~~and ~~transported~~storage ~~volumes,~~services ~~inclusive~~which ofdecreased ~~disruptions~~$27 inmillion ~~natural~~due ~~gas~~to ~~supply associated with Winter Storm Uri and~~ the recognition in 2020 of $116 million of previously reserved revenue upon the settlement of the MRT rate case with no comparable item in 2021, combined with interstate contract extensions at lower rates and terminations of certain intrastate firm transportation agreements.

•aOur $6transportation ~~million~~and ~~reduction~~storage insegment ~~lower~~gross ofmargin ~~cost~~increased or$68 ~~net~~million. ~~realizable~~The ~~value~~increase ~~adjustments~~was ~~related~~primarily due to ~~natural~~the ~~gas storage inventories and~~following:

•~~revenues~~system ~~from~~management ~~NGL~~activities ~~sales, less the cost of NGLs~~ increased $2 85 million primarily due to anhigher ~~increase~~average innatural ~~average~~gas ~~NGL~~sales prices, ~~partially~~less ~~offset~~the bycost ~~lower~~of ~~volumes.~~natural gas,

•volume-dependent transportation and storage revenues increased $8 million due to an increase in interstate transported volumes and assessed shipper imbalance penalties, partially offset by lower off-system intrastate transported volumes, 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,

•an $8 million reduction in lower of cost or net realizable value adjustments related to natural gas storage inventories and

•revenues from NGL sales, less the cost of NGLs increased $3 million due to an increase in average NGL prices, partially offset by lower volumes.

These increases were partially offset by:

•firm transportation and storage services decreased $2127 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 combined with interstate contract extensions at lower rates and terminations of certain intrastate firm transportation agreements,

•~~changes~~higher inrealized ~~the~~losses ~~fair~~on ~~value of~~ natural gas derivatives, ~~which~~of ~~decreased~~ $28 million and

•~~higher~~changes ~~realized~~in ~~losses~~the onfair value of natural gas derivatives, ofwhich decreased $1 million.

Our transportation and storage segment operation and maintenance and general and administrative expenses decreased $48 million. The decrease was primarily driven by a $69 million decrease in payroll-related 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 $3 million increase in ~~the~~loss ~~allowance~~contingencies ~~for doubtful accounts~~ and a $31 million increase due to a decrease in ~~loss~~capitalized ~~contingencies~~costs.

Our transportation and storage segment taxes other than income increased $1 million primarily due to additional assets placed in service.

Condensed Consolidated Interim Information

	Three Months Ended June 30,				Six Months EndedJune 30,
	Three Months Ended September 30,				Nine Months EndedSeptember 30,
	2021		2020		2021		2020
	(In millions)
Operating Income	$	~~124~~152	$	80100	$	~~330~~482	$	~~226~~326
Other Income (Expense):
Interest expense	(4241)		(4643)		(84125)		(93136)
Equity in earnings of equity method affiliate, net (1)	—		5		1		11
Equity in earnings (losses) of equity method affiliate, net (1)	4		(222)		5		(211)
Other, net	61		52		67		57
Total Other Expense	(36)		(36263)		(77113)		(77340)
Income Before Income Taxes	88		44		253		149
Income (Loss) Before Income Taxes	116		(163)		369		(14)
Income tax benefit	—		—		—		—
Net Income	$	88	$	44	$	253	$	149
Net Income (Loss)	$	116	$	(163)	$	369	$	(14)
Less: Net income (loss) attributable to noncontrolling interest	1—		—1		2		(76)
Net Income Attributable to Limited Partners	$	87	$	44	$	251	$	156
Net Income (Loss) Attributable to Limited Partners	$	116	$	(164)	$	367	$	(8)
Less: Series A Preferred Unit distributions	89		9		1726		1827
Net Income Attributable to Common Units	$	79	$	35	$	234	$	138
Net Income (Loss) Attributable to Common Units	$	107	$	(173)	$	341	$	(35)

_____________________

(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 ~~six~~nine months ended ~~June~~September 30, 2021 and 2020.

Three Months Ended June 30, 2021 compared to Three Months Ended June 30, 2020

Net Income Attributable to Limited Partners. We reported net income attributable to limited partners of $87 million in the three months ended June 30, 2021 compared to net income attributable to limited partners of $44 million in the three months ended June 30, 2020. The increase in net income attributable to limited partners of $43 million was primarily attributable to an increase in operating income of $44 million, a decrease in interest expense of $4 million and an increase of $1 million in Other, net, partially offset by a decrease in equity in earnings of equity method affiliate, net of $5 million and a $1 million change in net income (loss) attributable to noncontrolling interest in the three months ended June 30, 2021.

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Equity in Earnings of Equity Method Affiliate, net. Equity in earnings of equity method affiliate, net decreased $5 million due to a decrease in revenues as a result of contract expirations, partially offset by an increase in amortization of the basis differential.

Interest Expense. Interest expense decreased $4 million primarily due to lower interest rates on the Partnership’s short-term borrowings and lower debt levels.

Other, net. Other, net is primarily comprised of equity AFUDC for the three months ended June 30, 2021 and a gain on extinguishment of debt in the three months ended June 30, 2020.

Six Months Ended June 30, 2021 compared to Six Months Ended June 30, 2020

Net Income Attributable to Limited Partners. We reported net income attributable to limited partners of $251 million in the six months ended June 30, 2021 compared to net income attributable to limited partners of $156 million in the six months ended June 30, 2020. The increase in net income attributable to limited partners of $95 million was primarily attributable to an increase in operating income of $104 million and a decrease in interest expense of $9 million and an increase of $1 million in Other, net, partially offset by a $9 million change in net income (loss) attributable to noncontrolling interest and a decrease in equity in earnings of equity method affiliate, net of $10 million in the six months ended June 30, 2021.

Equity in Earnings of Equity Method Affiliate, net. Equity in earnings of equity method affiliate, net decreased $10 million due to a decrease in revenues as a result of contract expirations, partially offset by an increase in amortization of the basis differential.

Interest Expense. Interest expense decreased $9 million primarily due to lower interest rates on the Partnership’s short-term borrowings and lower debt levels.

Net Income (Loss) Attributable to Noncontrolling Interest. Net income (loss) attributable to noncontrolling interest changed $9 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.

Other, net. Other, net is primarily comprised of equity AFUDC for the six months ended June 30, 2021 and a gain on extinguishment of debt in the six months ended June 30, 2020.

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Three Months Ended September 30, 2021 compared to Three Months Ended September 30, 2020

Net Income (Loss) Attributable to Limited Partners. We reported net income attributable to limited partners of $116 million in the three months ended September 30, 2021 compared to net loss attributable to limited partners of $164 million in the three months ended September 30, 2020. The increase in net income attributable to limited partners of $280 million was primarily attributable to an increase in equity in earnings (losses) of equity method affiliate, net of $226 million, an increase in operating income of $52 million, a decrease in interest expense of $2 million and a $1 million change in net income (loss) attributable to noncontrolling interest, partially offset by a decrease of $1 million in Other, net in the three months ended September 30, 2021.

Equity in Earnings (Losses) of Equity Method Affiliate, net. Equity in earnings (losses) of equity method affiliate, net increased $226 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 $2 million primarily due to lower interest rates on the Partnership’s short-term borrowings and lower debt levels.

Other, net. Other, net is primarily comprised of equity AFUDC in the three months ended September 30, 2021 and interest income in the three months ended September 30, 2020.

Nine Months Ended September 30, 2021 compared to Nine Months Ended September 30, 2020

Net Income (Loss) Attributable to Limited Partners. We reported net income attributable to limited partners of $367 million in the nine months ended September 30, 2021 compared to net loss attributable to limited partners of $8 million in the nine months ended September 30, 2020. The increase in net income attributable to limited partners of $375 million was primarily attributable to an increase in equity in earnings (losses) of equity method affiliate, net of $216 million, an increase in operating income of $156 million and a decrease in interest expense of $11 million, partially offset by an $8 million change in net income (loss) attributable to noncontrolling interest in the nine months ended September 30, 2021.

Equity in Earnings (Losses) of Equity Method Affiliate, net. Equity in earnings (losses) of equity method affiliate, net increased $216 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 $11 million primarily due to lower interest rates on the Partnership’s short-term borrowings and lower debt levels.

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.

Other, net. Other, net is primarily comprised of equity AFUDC for the nine months ended September 30, 2021 and a gain on extinguishment of debt and interest income in the nine months ended September 30, 2020.

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Reconciliations of Non-GAAP Financial Measures

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

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

Three Months Ended June 30,

Six Months EndedJune 30,

Three Months Ended September 30,

Nine Months EndedSeptember 30,

2021

2020

2021

2020

(In millions)

Reconciliation of Gross margin to Total Revenues:

Consolidated

Product sales

~~460~~623

~~196~~280

1,~~087~~710

~~484~~764

Service revenues

~~327~~333

~~319~~316

~~670~~1,003

~~679~~995

Total Revenues

~~787~~956

~~515~~596

12,~~757~~713

1,~~163~~759

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

~~426~~565

~~177~~250

~~945~~1,510

~~403~~653

Gross margin

~~361~~391

~~338~~346

~~812~~1,203

~~760~~1,106

Reportable Segments

Gathering and Processing

Product sales

~~461~~625

~~193~~271

~~889~~1,514

~~468~~739

Service revenues

~~212~~214

~~198~~192

~~408~~622

~~400~~592

Total Revenues

~~673~~839

~~391~~463

12,~~297~~136

~~868~~1,331

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

~~437~~571

~~176~~244

~~835~~1,406

~~387~~631

Gross margin

~~236~~268

~~215~~219

~~462~~730

~~481~~700

Transportation and Storage

Product sales

~~135~~157

5979

~~467~~624

~~134~~213

Service revenues

~~118~~122

~~124~~126

~~268~~390

~~283~~409

Total Revenues

~~253~~279

~~183~~205

~~735~~1,014

~~417~~622

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

~~128~~154

5978

~~385~~539

~~137~~215

Gross margin

125

~~124~~127

~~350~~475

~~280~~407

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The following table shows the components of our gross margin.

	Fee-Based (1)
Six Months Ended June 30, 2021	Demand		Volume-Dependent		Commodity-Based (1)		Total
Nine Months Ended September 30, 2021	Demand		Volume-Dependent		Commodity-Based (1)		Total
Gathering and Processing Segment	12	%	7666	%	1222	%	100	%
Transportation and Storage Segment	6772	%	10	%	2318	%	100	%
Partnership Weighted Average	36	%	4743	%	1721	%	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 June 30,				Six Months EndedJune 30,
	Three Months Ended September 30,				Nine Months EndedSeptember 30,
	2021		2020		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	$	87	$	44	$	251	$	156
Net income (loss) attributable to limited partners	$	116	$	(164)	$	367	$	(8)
Depreciation and amortization expense	~~103~~104		105		~~209~~313		~~209~~314
Interest expense, net of interest income	4240		4543		84124		92135
Distributions received from equity method affiliate in excess of equity earnings	—(3)		41		3—		89
Non-cash equity-based compensation	4		3		8		7
Impairment of equity method affiliate investment	—		225		—		225
Change in fair value of derivatives (1)	19		12		29		2
Non-cash equity-based compensation	4		3		12		10
Equity AFUDC and other non-cash items (2)	(4)		17		(5)		22
Change in fair value of derivatives (1)	7		15		36		17
Equity AFUDC and other non-cash items (2)	1		1		(4)		23
Impairments of property, plant and equipment and goodwill	—		—		—		28
Gain on extinguishment of debt	—		~~(5)~~—		—		(5)
Noncontrolling Interest Share of Adjusted EBITDA	—		~~(1)~~—		—		(9)
Adjusted EBITDA	$	~~251~~269	$	~~224~~229	$	~~579~~848	$	~~510~~739
Series A Preferred Unit distributions (3)	(89)		(9)		(1726)		(1827)
Distributions for phantom and performance units (4)	—(1)		~~(1)~~—		—(1)		(1)
Adjusted interest expense (5)	(4139)		(4542)		(83122)		(92134)
Maintenance capital expenditures	(1827)		(2231)		(3461)		(3869)
Current income taxes	—		1—		—		1
DCF	$	~~184~~193	$	~~148~~147	$	~~445~~638	$	~~362~~509
Distributions related to common unitholders (6)	$	72	$	72	$	~~144~~216	$	~~144~~216
Distribution coverage ratio (7)	2.5668		2.0604		32.0995		2.5136

____________________

(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 items includes write-downs and 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 months ended ~~June~~September 30, 2021 and 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)Represents cash distributions declared for common units outstanding as of each respective period. Amounts for 2021 reflect estimated cash distributions for common units outstanding for the quarter ended ~~June~~September 30, 2021.

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

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	Three Months Ended June 30,				Six Months EndedJune 30,
	Three Months Ended September 30,				Nine Months EndedSeptember 30,
	2021		2020		2021		2020
	(In millions)
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities	$	~~190~~265	$	~~111~~232	$	~~413~~678	$	~~311~~543
Interest expense, net of interest income	4240		4543		84124		92135
Noncontrolling interest share of cash provided by operating activities	~~(2)~~—		(1)		(3)		(23)
Current income taxes	—		1—		—		1
Equity AFUDC and other non-cash items (1)	2—		(2)		(1)		2—
Proceeds from insurance	~~(1)~~—		—1		—		—1
Changes in operating working capital which (provided) used cash:
Accounts receivable	4155		303		75130		(3027)
Accounts payable	(453)		12(24)		(1467)		7046
Other, including changes in noncurrent assets and liabilities	(3642)		12(39)		(749)		5617
Return of investment in equity method affiliate	—(3)		41		3—		89
Change in fair value of derivatives (2)	197		1215		2936		217
Adjusted EBITDA	$	~~251~~269	$	~~224~~229	$	~~579~~848	$	~~510~~739

____________________

(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 June 30,				Six Months EndedJune 30,
	Three Months Ended September 30,				Nine Months EndedSeptember 30,
	2021		2020		2021		2020
	(In millions)
Reconciliation of Adjusted interest expense to Interest expense:
Interest expense	$	4241	$	4643	$	84125	$	93136
Interest income	—(1)		~~(1)~~—		—(1)		(1)
Amortization of premium on long-term debt	—		—		—		1
Capitalized interest on expansion capital	1—		1		2		12
Amortization of debt expense and discount	(21)		(12)		(34)		(24)
Adjusted interest expense	$	4139	$	4542	$	83122	$	92134

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

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 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 ~~June~~September 30, 2021 are the same as those described in our Annual Report.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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Commodity Price Risk

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

Based on our forecasted volumes, prices and contractual arrangements, we estimate approximately 1822% of our total gross margin for the twelve months ended December 31, 2021, is directly exposed to changes in commodity prices, excluding the impact of hedges and contractual floors related to commodity prices in certain agreements.

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 ~~six~~three months. Based on a sensitivity analysis regarding our direct commodity exposure, a 10% decrease in prices from forecasted levels would decrease net income by approximately $74 million for natural gas and ethane and $85 million for NGLs (other than ethane) and condensate, excluding the impact of hedges, for the remaining ~~six~~three months ending December 31, 2021.

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt 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 $~~971~~850 million outstanding borrowings under commercial paper and 2019 Term Loan Agreement as of ~~June~~September 30, 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 $109 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 ~~June~~September 30, 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 ~~June~~September 30, 2021. Based on such evaluation, our management has concluded that, as of ~~June~~September 30, 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.

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

Changes in Internal Controls Over Financial Reporting

There were no changes in our internal controls over financial reporting during the quarter ended ~~June~~September 30, 2021, that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. Risk factors relating to the Partnership are set forth under “Risk Factors” in our Annual Report. No other material changes to such risk factors have occurred during the three months ended ~~June~~September 30, 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.

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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

4.6

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

4.7

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

4.8

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.

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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:

~~August~~November 41, 2021

By:

/s/ Tom Levescy

Tom Levescy

Senior Vice President, Chief Accounting Officer and Controller

(Principal Accounting Officer)

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