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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 _______________________________________
FORM 10-Q
 _______________________________________
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
THE SECURITIES AND EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 20172021
or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
☐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
 _______________________________________enbl-20210930_g1.jpg
ENABLE MIDSTREAM PARTNERS, LP
(Exact name of registrant as specified in its charter)
 _______________________________________
Delaware72-1252419
(State or other jurisdiction of
incorporation or organization)		(I.R.S. Employer
Identification No.)
Delaware72-1252419
(State or jurisdiction of
incorporation or organization)
499 West Sheridan Avenue, Suite 1500 Oklahoma City, Oklahoma
73102
(I.R.S. Employer
Identification No.)
Address of Principal Executive Offices)		(Zip Code)
One Leadership Square
211 North Robinson Avenue
Suite 150
Oklahoma City, Oklahoma 73102
(Address of principal executive offices)
(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:
 _______________________________________
Title of each classTrading symbol(s)Name of each exchange on which registered
Common Units Representing Limited Partner InterestsENBLNew 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. þYes  ¨☒    No☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  þYes  ¨☒   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☐þAccelerated FilerAccelerated filer¨☒
Non-accelerated filer☐
¨ (Do not check if a smaller reporting company)
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  þ☐     No☒
As of October 13, 2017,15, 2021, there were 432,566,554435,891,855 common units outstanding.


Table of Contents

ENABLE MIDSTREAM PARTNERS, LP
FORM 10-Q
TABLE OF CONTENTS
 
Page
1
4
Page
GLOSSARY OF TERMS
1
FORWARD-LOOKING STATEMENTS
3
Part I - FINANCIAL INFORMATION
Condensed Consolidated Statements of Income
46
Condensed Consolidated Statements of Comprehensive Income
7
Condensed Consolidated Balance Sheets
58
Condensed Consolidated Statements of Cash Flows
69
Condensed Consolidated Statements of Partners' Equity
710
Notes to Unaudited Condensed Consolidated Financial Statements
811
2835
4251
4252
Part II - OTHER INFORMATION
4353
4353
4353
4555


AVAILABLE INFORMATION


Our website is www.enablemidstream.com. On the investor relations tab of our website, http://investors.enablemidstream.com, we make available free of charge a variety of information to investors. Our goal is to maintain the investor relations tab of our website as a portal through which investors can easily find or navigate to pertinent information about us, including but not limited to:
•our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after we electronically file that material with or furnish it to the SEC;
•press releases on quarterly distributions, quarterly earnings, and other developments;
•governance information, including our governance guidelines, committee charters, and code of ethics and business conduct;
•information on events and presentations, including an archive of available calls, webcasts, and presentations;
•news and other announcements that we may post from time to time that investors may find useful or interesting; and
•opportunities to sign up for email alerts and RSS feeds to have information pushed in real time.


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







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GLOSSARY OF TERMS
Adjusted EBITDA.A non-GAAP measure calculated as net income attributable to limited partners plus depreciation and amortization expense, interest expense, income tax expense, distributions received from equity method affiliate in excess of equity earnings, non-cash equity-based compensation, impairments, changes in fair value of derivatives, noncontrolling interest share of Adjusted EBITDA and certain other non-cash gains and losses (including gains and losses on sales of assets and write-downs of materials and supplies).Measurements
Adjusted interest expense.Bbl.A non-GAAP measure calculated as interest expense plus amortization of premium on long-term debt and capitalized interest, less amortization of debt expense and discount.
Annual Report.Annual Report on Form 10-K for the year ended December 31, 2016.
ArcLight.ArcLight Capital Partners, LLC, a Delaware limited liability company, its affiliated entities ArcLight Energy Partners Fund V, L.P., ArcLight Energy Partners Fund IV, L.P., Bronco Midstream Partners, L.P., Bronco Midstream Infrastructure LLC and Enogex Holdings LLC, and their respective general partners and subsidiaries.
ASU.Accounting Standards Update.
ATM Program.ATM Equity Offering Sales Agreement entered into on May 12, 2017 in connection with an at-the-market program, under which the Partnership may issue and sell common units having an aggregate offering price of up to $200 million in quantities, by sales methods and at prices determined by market conditions and other factors at the time of such sales.
Barrel.42 U.S. gallons of petroleum products.
Bbl.Bbl/d.Barrel.
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.
CenterPoint Energy.MBbl.CenterPoint Energy, Inc., a Texas corporation, and its subsidiaries.Thousand barrels.
CERC.MBbl/d.CenterPoint Energy Resources Corp., a Delaware corporation.Thousand barrels per day.
Condensate.MMBtu.A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.Million British thermal units.
DCF.MMcf.AMillion cubic feet.
MMcf/d.Million cubic feet per day.
TBtu.Trillion British thermal units.
TBtu/d.Trillion British thermal units per day.
Abbreviations
AFUDCAllowance 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 and distributions for phantom and performance units. taxes.
Distribution coverage ratio.A non-GAAP measure calculated as DCF divided by distributions related to common and subordinated unitholders.
DRIP.EBITDA.Distribution Reinvestment Plan entered into on June 23, 2016, which offers owners of our commonEarnings before interest, taxes, depreciation and subordinated units the ability to purchase additional common units by reinvesting all or a portion of the cash distributions paid to them on their common or subordinated units.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 GP.Enable GP,Oklahoma Crude Services, LLC, formerly Velocity Holdings, LLC, a Delaware limited liability companywholly owned subsidiary of the Partnership that provides crude oil and condensate gathering services to customers in the general partnerSCOOP and STACK plays of Enable Midstream Partners, LP.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.
EOIT Senior Notes.EPA.$250 million 6.25% senior notes due 2020.Environmental Protection Agency.
Exchange Act.Securities Exchange Act of 1934, as amended.
FASB.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.
FASB.Financial Accounting Standards Board.
FERC.Federal Energy Regulatory Commission.
Fractionation.FTC.The separation of the heterogeneous mixture of extracted NGLs into individual components for end-use sale.United States Federal Trade Commission.
GAAP.GenerallyAccounting principles generally accepted accounting principles in the United States.States of America.

Gas imbalance.The difference between the actual amounts of natural gas delivered from or received by a pipeline, as compared to the amounts scheduled to be delivered or received.
General Partner.Enable GP, LLC, a Delaware limited liability company, the general partner of Enable Midstream Partners, LP.
Gross margin.LDC.A non-GAAP measure calculated as Total revenues minus cost of natural gas and natural gas liquids, excluding depreciation and amortization.
IPO.Initial public offering of Enable Midstream Partners, LP.
LDC.Local distribution company involved in the delivery of natural gas to consumers within a specific geographic area.
LIBOR.London Interbank Offered Rate.
MBbl.Thousand barrels.
MBbl/d.Thousand barrels per day.
MFA.Master Formation Agreement dated as of March 14, 2013.
MMcf.MRT.Million cubic feet of natural gas.
MMcf/d.Million cubic feet per day.
MRT.Enable Mississippi River Transmission, LLC, a wholly owned subsidiary of the Partnership that operates aan approximately 1,600-mile interstate pipeline that provides natural gas transportation and storage services principally in Texas, Arkansas, Louisiana, Missouri and Illinois.
NGLs.NGA.Natural Gas Act of 1938.
NGL(s).Natural gas liquids,liquid(s), which are the hydrocarbon liquids contained within the natural gas stream including condensate.
NYMEX.
NYSE.New York MercantileStock Exchange.
OGE Energy.OGE Energy Corp., an Oklahoma corporation, and its subsidiaries.
Partnership.OPEC.Enable Midstream Partners, LP, and its subsidiaries.Organization of the Petroleum Exporting Countries.
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Partnership Agreement.PHMSA.Fourth AmendedPipeline and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP dated as of June 22, 2016.Hazardous Materials Safety Administration.
Revolving Credit Facility.S&P.$1.75 billion senior unsecured revolving credit facility.Standard & Poor’s Rating Services.
SEC.SCOOP.South Central Oklahoma Oil Province.
SEC.Securities and Exchange Commission.
Securities Act.SESH.Securities Act of 1933, as amended.
Series A Preferred Units.10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in the Partnership.
SESH.Southeast Supply Header, LLC, in which the Partnership owns a 50% interest, that operates an approximately 290-mile interstate natural gas pipeline from Perryville, Louisiana to southwestern Alabama near the Gulf Coast.
TBtu.STACK.Trillion British thermal units.Sooner Trend Anadarko Basin Canadian and Kingfisher Counties.
TBtu/d.Trillion British thermal units per day.
WTI.West Texas Intermediate.Terms and Definitions
20152019 Term Loan Agreement.$450 million unsecuredUnsecured term loan agreement.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.
2019 Notes.$500 million 2.400% senior notes due 2019.
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.
20442028 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.

AAll statements, other than statements of historical fact, included in this Form 10-Q regarding the prospects of our industry, our anticipated financial performance, management’s plans and objectives for future operations, planned capital expenditures, business prospects, outcome of regulatory proceedings, market conditions, the 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 this report and in our Annual Report on Form 10-K for the year ended December 31, 2016.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;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 our General Partner;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 its economic effects;
•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;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)(Unaudited)
 Three Months Ended September 30,Nine Months Ended
September 30,
 2021202020212020
 (In millions, except per unit data)
Revenues (including revenues from affiliates (Note 13)):
Product sales$623 $280 $1,710 $764 
Service revenues333 316 1,003 995 
Total Revenues956 596 2,713 1,759 
Cost and Expenses (including expenses from affiliates (Note 13)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)565 250 1,510 653 
Operation and maintenance92 96 267 313 
General and administrative27 28 89 73 
Depreciation and amortization104 105 313 314 
Impairments of property, plant and equipment and goodwill (Note 7)— — — 28 
Taxes other than income tax16 17 52 52 
Total Cost and Expenses804 496 2,231 1,433 
Operating Income152 100 482 326 
Other Income (Expense):
Interest expense(41)(43)(125)(136)
Equity in earnings (losses) of equity method affiliate, net4 (222)5 (211)
Other, net1 2 7 7 
Total Other Expense(36)(263)(113)(340)
Income (Loss) Before Income Tax116 (163)369 (14)
Income tax benefit— — — — 
Net Income (Loss)$116 $(163)$369 $(14)
Less: Net income (loss) attributable to noncontrolling interest— 1 2 (6)
Net Income (Loss) Attributable to Limited Partners$116 $(164)$367 $(8)
Less: Series A Preferred Unit distributions (Note 6)9 9 26 27 
Net Income (Loss) Attributable to Common Units (Note 5)$107 $(173)$341 $(35)

Basic and diluted earnings (loss) per unit (Note 5)
Basic$0.24 $(0.40)$0.78 $(0.08)
Diluted$0.24 $(0.40)$0.76 $(0.08)
 
 Three Months Ended 
 September 30,
Nine Months Ended 
 September 30,
 2017
2016
2017
2016
 (In millions, except per unit data)
Revenues (including revenues from affiliates (Note 11)):










Product sales$396

$326

$1,136

$837
Service revenue309

294

861

821
Total Revenues705

620

1,997

1,658
Cost and Expenses (including expenses from affiliates (Note 11)):










Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)349

268

936

717
Operation and maintenance91

87

277

275
General and administrative23

21

71

68
Depreciation and amortization90

84

267

248
Impairments (Note 5)—

8

—

8
Taxes other than income tax15

13

47

43
Total Cost and Expenses568

481

1,598

1,359
Operating Income137

139

399

299
Other Income (Expense):






Interest expense (including expenses from affiliates (Note 11))(31)
(26)
(89)
(74)
Equity in earnings of equity method affiliate7

8

21

22
Total Other Expense(24)
(18)
(68)
(52)
Income Before Income Tax113

121

331

247
Income tax expense—

2

2

3
Net Income$113

$119

$329

$244
Less: Net income attributable to noncontrolling interest—

—

1

—
Net Income Attributable to Limited Partners$113

$119

$328

$244
Less: Series A Preferred Unit distributions (Note 4)9

9

27

13
Net Income Attributable to Common and Subordinated Units (Note 3)$104

$110

$301

$231












Basic earnings per unit (Note 3)










Common units$0.24

$0.26

$0.70

$0.55
Subordinated units$0.24

$0.26

$0.69

$0.55
Diluted earnings per unit (Note 3)








Common units$0.24

$0.26

$0.69

$0.55
Subordinated units$0.24

$0.26

$0.69

$0.55
See Notes to the Unaudited Condensed Consolidated Financial Statements

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ENABLE MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
 Three Months Ended September 30,Nine Months Ended
September 30,
 2021202020212020
 (In millions)
Net income (loss)$116 $(163)$369 $(14)
Other comprehensive income (loss):
Change in fair value of interest rate derivative instruments— — — (7)
Reclassification of interest rate derivative losses to net income1 2 4 3 
Other comprehensive income (loss)1 2 4 (4)
Comprehensive income (loss)117 (161)373 (18)
Less: Comprehensive income (loss) attributable to noncontrolling interest— 1 2 (6)
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)
September 30, 2021December 31, 2020
(In millions)
Current Assets:
Cash and cash equivalents$36 $3 
Accounts receivable, net of allowance for doubtful accounts (Note 1)384 248 
Accounts receivable—affiliated companies9 15 
Inventory43 42 
Gas imbalances26 42 
Other current assets, net of allowance for doubtful accounts (Note 1)38 31 
Total current assets536 381 
Property, Plant and Equipment:
Property, plant and equipment13,396 13,220 
Less: Accumulated depreciation and amortization2,785 2,555 
Property, plant and equipment, net10,611 10,665 
Other Assets:
Intangible assets, net492 539 
Investment in equity method affiliate76 76 
Other65 68 
Total other assets633 683 
Total Assets$11,780 $11,729 
Current Liabilities:
Accounts payable$220 $149 
Accounts payable—affiliated companies2 2 
Current portion of long-term debt800 — 
Short-term debt50 250 
Taxes accrued55 34 
Gas imbalances28 19 
Other144 128 
Total current liabilities1,299 582 
Other Liabilities:
Accumulated deferred income taxes, net4 5 
Regulatory liabilities27 25 
Other63 71 
Total other liabilities94 101 
Long-Term Debt3,154 3,951 
Commitments and Contingencies (Note 14)00
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at September 30, 2021 and December 31, 2020)362 362 
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(2)(6)
Noncontrolling interest25 26 
Total Partners’ Equity7,233 7,095 
Total Liabilities and Partners’ Equity$11,780 $11,729 
See Notes to the Unaudited Condensed Consolidated Financial Statements
8
 September 30,
2017		 December 31,
2016
 (In millions)
Current Assets: 
Cash and cash equivalents$8
 $6
Restricted cash14
 17
Accounts receivable, net of allowance for doubtful accounts321
 249
Accounts receivable—affiliated companies13
 13
Inventory40
 41
Gas imbalances16
 41
Other current assets34
 29
Total current assets446
 396
Property, Plant and Equipment:   
Property, plant and equipment11,824
 11,567
Less accumulated depreciation and amortization1,650
 1,424
Property, plant and equipment, net10,174
 10,143
Other Assets:   
Intangible assets, net286
 306
Investment in equity method affiliate320
 329
Other36
 38
Total other assets642
 673
Total Assets$11,262
 $11,212
Current Liabilities:   
Accounts payable$198
 $181
Accounts payable—affiliated companies3
 3
Current portion of long-term debt450
 —
Taxes accrued54
 30
Gas imbalances18
 35
Other108
 113
Total current liabilities831
 362
Other Liabilities:   
Accumulated deferred income taxes, net12
 10
Regulatory liabilities21
 19
Other38
 34
Total other liabilities71
 63
Long-Term Debt2,669
 2,993
Commitments and Contingencies (Note 12)
 
Partners’ Equity:   
Series A Preferred Units (14,520,000 issued and outstanding at September 30, 2017 and December 31, 2016)362
 362
Common units (432,563,899 issued and outstanding at September 30, 2017 and 224,535,454 issued and outstanding at December 31, 2016, respectively)7,317
 3,737
Subordinated units (0 issued and outstanding at September 30, 2017 and 207,855,430 issued and outstanding at December 31, 2016, respectively)—
 3,683
Noncontrolling interest12
 12
Total Partners’ Equity7,691
 7,794
Total Liabilities and Partners’ Equity$11,262
 $11,212

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ENABLE MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30,
20212020
(In millions)
Cash Flows from Operating Activities:
Net income (loss)$369 $(14)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization313 314 
Deferred income taxes— 1 
Impairments of property, plant and equipment and goodwill— 28 
Net loss on sale/retirement of assets1 17 
Equity in (earnings) losses of equity method affiliate, net(5)211 
Return on investment in equity method affiliate5 14 
Equity-based compensation12 10 
Amortization of debt costs and discount4 3 
Other, net(7)(5)
Changes in other assets and liabilities:
Accounts receivable, net(136)14 
Accounts receivable—affiliated companies6 13 
Inventory(1)4 
Gas imbalance assets16 (3)
Other current assets, net(11)— 
Other assets3 4 
Accounts payable67 (47)
Accounts payable—affiliated companies— 1 
Gas imbalance liabilities9 (5)
Other current liabilities42 (14)
Other liabilities(9)(3)
Net cash provided by operating activities678 543 
Cash Flows from Investing Activities:
Capital expenditures (excluding equity AFUDC)(204)(152)
Proceeds from sale of assets3 19 
Proceeds from insurance— 1 
Return of investment in equity method affiliate— 9 
Other, net3 3 
Net cash used in investing activities(198)(120)
Cash Flows from Financing Activities:
Decrease in short-term debt(200)179 
Repayment of long-term debt— (267)
Proceeds from Revolving Credit Facility— 869 
Repayment of Revolving Credit Facility— (869)
Distributions to common unitholders(216)(288)
Distributions to preferred unitholders(26)(27)
Distributions to non-controlling interests(3)(5)
Cash paid for employee equity-based compensation(2)(1)
Net cash used in financing activities(447)(409)
Net Increase in Cash, Cash Equivalents and Restricted Cash33 14 
Cash, Cash Equivalents and Restricted Cash at Beginning of Period3 4 
Cash, Cash Equivalents and Restricted Cash at End of Period$36 $18 
See Notes to the Unaudited Condensed Consolidated Financial Statements
9
 Nine Months Ended 
 September 30,
 2017 2016
 (In millions)
Cash Flows from Operating Activities: 
Net income$329
 $244
Adjustments to reconcile net income to net cash provided by operating activities:   
Depreciation and amortization267
 248
Deferred income taxes2
 4
Impairments—
 8
Loss on sale/retirement of assets7
 9
Equity in earnings of equity method affiliate(21) (22)
Return on investment in equity method affiliate21
 22
Equity-based compensation12
 9
Amortization of debt costs and discount (premium)(1) (2)
Changes in other assets and liabilities:   
Accounts receivable, net(72) (33)
Accounts receivable—affiliated companies—
 8
Inventory1
 11
Gas imbalance assets25
 3
Other current assets(5) 3
Other assets2
 (1)
Accounts payable(16) (84)
Accounts payable—affiliated companies—
 (4)
Gas imbalance liabilities(17) (3)
Other current liabilities17
 68
Other liabilities5
 10
Net cash provided by operating activities556
 498
Cash Flows from Investing Activities:   
Capital expenditures(250) (289)
Proceeds from sale of assets1
 1
Return of investment in equity method affiliate9
 18
Net cash used in investing activities(240) (270)
Cash Flows from Financing Activities:   
Proceeds from long term debt, net of issuance costs691
 —
Proceeds from revolving credit facility591
 838
Repayment of revolving credit facility(1,154) (393)
Decrease in short-term debt—
 (236)
Repayment of notes payable—affiliated companies—
 (363)
Proceeds from issuance of Series A Preferred Units, net of issuance costs—
 362
Distributions(443) (417)
Cash taxes paid for employee equity-based compensation(2) —
Net cash used in financing activities(317) (209)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash(1) 19
Cash, Cash Equivalents and Restricted Cash at Beginning of Period23
 4
Cash, Cash Equivalents and Restricted Cash at End of Period$22
 $23

Table of Contents
ENABLE MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY
(Unaudited)
Nine Months Ended September 30, 2021
 Series A
Preferred
Units		Common
Units		Accumulated Other Comprehensive LossNoncontrolling
Interest		Total Partners’
Equity
 UnitsValueUnitsValueValueValueValue
 (In millions)
Balance as of December 31, 202015 $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, 202115 $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, 202115 $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, 202115 $362 436 $6,848 $(2)$25 $7,233 

Nine Months Ended September 30, 2020
Series A Preferred UnitsCommon UnitsAccumulated Other Comprehensive LossNoncontrolling InterestTotal Partners’ Equity
UnitsValueUnitsValueValueValueValue
(In millions)
Balance as of December 31, 201915 $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, 202015 $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, 202015 $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, 202015 $362 435 $6,695 $(7)$26 $7,076 
See Notes to the Unaudited Condensed Consolidated Financial Statements
10
 
Series A
Preferred
Units
 
Common
Units
 
Subordinated
 Units
 
Noncontrolling
Interest
 
Total Partners’
Equity
 Units Value Units Value Units Value Value Value
 (In millions)
Balance as of December 31, 2015—
 $—
 214
 $3,714
 208
 $3,805
 $12
 $7,531
Net income—
 13
 —
 117
 —
 114
 —
 244
Issuance of Series A Preferred Units15
 362
 —
 —
 —
 —
 —
 362
Distributions—
 (13) —
 (205) —
 (198) (1) (417)
Equity-based compensation, net of units for employee taxes—
 —
 —
 9
 —
 —
 —
 9
Balance as of September 30, 201615
 $362
 214
 $3,635
 208
 $3,721
 $11
 $7,729
                
Balance as of December 31, 201615
 $362
 224
 $3,737
 208
 $3,683
 $12
 $7,794
Net income—
 27
 —
 167
 —
 134
 1
 329
Conversion of subordinated units—
 —
 208
 3,619
 (208) (3,619) —
 —
Distributions—
 (27) —
 (216) —
 (198) (1) (442)
Equity-based compensation, net of units for employee taxes—
 —
 1
 10
 —
 —
 —
 10
Balance as of September 30, 201715
 $362
 433
 $7,317
 —
 $—
 $12
 $7,691

Table of Contents
ENABLE MIDSTREAM PARTNERS, LP
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 


(1) Summary of Significant Accounting Policies


Organization

Enable Midstream Partners, LP (Partnership)(the Partnership) is a Delaware limited partnership formed on May 1, 2013 by CenterPoint Energy, OGE Energy and ArcLight. The Partnership’swhose assets and operations are organized into two2 reportable segments: (i) gathering and processing and (ii) transportation and storage. TheOur gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers and crude oil, condensate and produced water gathering services to our producer and refiner customers. The transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers. The Partnership’sOur 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, an interstatea 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 two2 representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership’s Chief Executive Officer and three3 independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP.


As of September 30, 2017,2021, CenterPoint Energy held approximately 54.1%53.7% or 233,856,623 of the Partnership’s common units, and OGE Energy held approximately 25.7%25.5% or 110,982,805 of the Partnership’s common units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. See Note 4 for further information related to the 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 (Enable GP)general partner on an annual or continuing basis and may not remove Enable GP, its current general partner, without at least a 75% vote by all unitholders, including all units held by the Partnership’s limited partners, and Enable GP and its affiliates, voting together as a single class.

As of September 30, 2017,2021, the Partnership owned a 50% interest in SESH. See Note 68 for further discussion of SESH. For the nine months ended 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 fourth 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 closing, we must continue to operate the Partnership as a stand-alone company.

11
Table of Contents
Basis of Presentation


The accompanying condensed consolidated financial statementsCondensed 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 statementsCondensed Consolidated Financial Statements and related notes should be read in conjunction with the consolidated financial statementsConsolidated Financial Statements and related notes included in our Annual Report.


 These condensed consolidated financial statementsThe Condensed Consolidated Financial Statements and the related financial statement disclosuresnotes reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. Amounts reported in the Partnership’s Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures, and (d) acquisitions and dispositions of businesses, assets and other interests.interests, and (e) the impact of the ongoing COVID-19 pandemic and its economic effects, 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 14.16.


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.


Restricted CashSales and Retirements of Assets


Restricted cash consistsOn 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 cashour gathering and processing segment. We have ceased operation of this system and are in the process of retiring it. We recognized a loss on retirement of approximately $20 million during the nine months ended September 30, 2020, which is restricted by agreements with third parties. Theincluded in Operation and maintenance expense in the Condensed Consolidated Balance Sheets have $14 million and $17 millionStatements of restricted cash as of September 30, 2017 and December 31, 2016, respectively.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 specific identificationthe 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 estimates offorecast information that could result in future uncollectable amounts. On an ongoing basis, management evaluateswe 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 historical bad debt write-offs,credit losses, the aging of receivables, and specific customer circumstances that may impact their ability to pay the amounts due. Based on this review, management determined that a $3 milliondue and current and forecast economic conditions over the assets contractual lives. The following table summarizes the required allowance for doubtful accounts was required at eachaccounts.
12
Table of September 30, 2017Contents
September 30, 2021December 31, 2020
(In millions)
Accounts receivable$1 $1 
Other current assets1 3 
Total Allowance for doubtful accounts$2 $4 

Inventory

Natural gas inventory is held, through the transportation and December 31, 2016.


(2) New Accounting Pronouncements

Accounting Standardsstorage segment, to be Adopted in Future Periods

Revenue from Contracts with Customers

In May 2014,provide operational support for pipeline deliveries and to manage leased intrastate storage capacity. Natural gas liquids inventory is held, through the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which supersedes the revenue recognition requirements in “Revenue Recognition (Topic 605).” Topic 606 is based on the core principle that revenue is recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Topic 606 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract.

Topic 606 is effective for fiscal years beginning after December 15, 2017. We continue to evaluate the impact this standard will have on the Partnership, which includes our review of contracts and transaction types across all our business segments. We continue to review the potential impact on certain commodity-based gathering and processing contract types. Duesegment, due to this ongoing analysis, we cannot yet determinetiming differences between the quantitative impact on revenuesproduction 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 cost ofnet realizable value. The Partnership recorded write-downs to net realizable value related to natural gas and natural gas liquids from the adoptioninventory of Topic 606, however, we currently believe the adoption will not have a material impact on operating income or net income. Based on our analysis to date, we do not expect material changes in the timing of revenue recognition or our accounting policies. We continue to developzero and evaluate our Topic 606 disclosures, as well as changes to internal controls necessary for adoption. The Partnership will adopt the revenue recognition standard in the first quarter of 2018 and expects to adopt Topic 606 using the modified retrospective method. 

Leases

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” This standard requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Partnership expects to adopt this standard in the first quarter of 2019 and is currently evaluating the impact of this standard on our Condensed Consolidated Financial Statements and related disclosures. In connection with our assessment work, we formed an implementation work team and are continuing our review of our contracts relative to the provisions of the lease standard.

Financial Instruments—Credit Losses

In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This standard requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions, and reasonable and supportable forecasts in order to

record credit losses in a more timely matter. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.

Income Taxes

In October 2016, the FASB issued ASU No. 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory.” This standard requires entities to recognize the tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The standard is effective for interim and annual reporting periods beginning after December 15, 2017, although early adoption is permitted as of the beginning of an annual period (i.e., only in the first interim period). The guidance requires application using a modified retrospective approach. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.



(3) Earnings Per Limited Partner Unit

The following table illustrates the Partnership’s calculation of earnings per unit for common and subordinated units:
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (In millions, except per unit data)
Net income$113
 $119
 $329
 $244
Net income attributable to noncontrolling interest—
 —
 1
 —
Series A Preferred Unit distribution9
 9
 27
 13
General partner interest in net income—
 —
 —
 —
Net income available to common and subordinated unitholders$104
 $110
 $301
 $231
        
Net income allocable to common units$71
 $56
 $174
 $117
Net income allocable to subordinated units33
 54
 127
 114
Net income available to common and subordinated unitholders$104
 $110
 $301
 $231
        
Net income allocable to common units$71
 $56
 $174
 $117
Dilutive effect of Series A Preferred Unit distributions—
 —
 —
 —
Diluted net income allocable to common units71
 56
 174
 117
Diluted net income allocable to subordinated units33
 54
 127
 114
Total$104
 $110
 $301
 $231
        
Basic weighted average number of outstanding       
Common units(1)
298
 214
 250
 214
Subordinated units 
136
 208
 183
 208
Total434
 422
 433
 422
        
Basic earnings per unit       
Common units$0.24
 $0.26
 $0.70
 $0.55
Subordinated units$0.24
 $0.26
 $0.69
 $0.55
        
Basic weighted average number of outstanding common units298
 214
 250
 214
Dilutive effect of Series A Preferred Units—
 —
 —
 —
Dilutive effect of performance units1
 —
 1
 —
Diluted weighted average number of outstanding common units299
 214
 251
 214
Diluted weighted average number of outstanding subordinated units136
 208
 183
 208
Total435
 422
 434
 422
        
Diluted earnings per unit       
Common units$0.24
 $0.26
 $0.69
 $0.55
Subordinated units$0.24
 $0.26
 $0.69
 $0.55
____________________
(1)Basic weighted average number of outstanding common units for the three and nine months ended September 30, 2017 includes approximately one$2 million time-based phantom units.

See Note 4 for discussion of the expiration of the subordination period.



The dilutive effect of the unit-based awards discussed in Note 13 was less than $0.01 per unit during each of the three months ended September 30, 20172021 and 20162020, respectively, and for$1 million and $9 million during the nine months ended September 30, 2016.2021 and 2020, respectively.




(4) 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 and subordinated unitholders, as applicable, during 2016 and 2017 (in millions, except for per unit amounts):
Quarter Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution
September 30, 2017(1)
 November 14, 2017 November 21, 2017 $0.318
 $138
June 30, 2017 August 22, 2017 August 29, 2017 $0.318
 $138
March 31, 2017 May 23, 2017 May 30, 2017 $0.318
 $137
December 31, 2016 February 21, 2017 February 28, 2017 $0.318
 $137
September 30, 2016 November 14, 2016 November 22, 2016 $0.318
 $134
June 30, 2016 August 16, 2016 August 23, 2016 $0.318
 $134
March 31, 2016 May 6, 2016 May 13, 2016 $0.318
 $134
December 31, 2015 February 2, 2016 February 12, 2016 $0.318
 $134
_____________________
(1)The board of directors of Enable GP declared this $0.318 per common unit cash distribution on October 31, 2017, to be paid on November 21, 2017, to common unitholders of record at the close of business on November 14, 2017.

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2016 and 2017 (in millions, except for per unit amounts):
Quarter Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution
September 30, 2017(1)
 October 31, 2017 November 14, 2017 $0.625
 $9
June 30, 2017 July 31, 2017 August 14, 2017 $0.625
 $9
March 31, 2017 May 2, 2017 May 12, 2017 $0.625
 $9
December 31, 2016 February 10, 2017 February 15, 2017 $0.625
 $9
September 30, 2016 November 1, 2016 November 14, 2016 $0.625
 $9
June 30, 2016 August 2, 2016 August 12, 2016 $0.625
 $9
March 31, 2016 (2)
 May 6, 2016 May 13, 2016 $0.2917
 $4
_____________________
(1)The board of directors of Enable GP declared a $0.625 per Series A Preferred Unit cash distribution on October 31, 2017, to be paid on November 14, 2017, to Series A Preferred unitholders of record at the close of business on October 31, 2017.
(2)The prorated quarterly distribution for the Series A Preferred Units is for a partial period beginning on February 18, 2016, and ending on March 31, 2016, which equates to $0.625 per unit on a full-quarter basis or $2.50 per unit on an annualized basis.

General Partner Interest and Incentive Distribution Rights

Enable GP owns a non-economic general partner interest in the Partnership and thus will not be entitled to distributions that the Partnership makes prior to the liquidation of the Partnership in respect of such general partner interest. Enable GP currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash the Partnership distributes from operating surplus (as defined in the Partnership Agreement) in excess of $0.330625 per unit per

quarter. The maximum distribution of 50.0% does not include any distributions that Enable GP or its affiliates may receive on common units that they own.

Expiration of Subordination Period

The financial tests required for conversion of all subordinated units were met and the 207,855,430 outstanding subordinated units converted into common units on a one-for-one basis on August 30, 2017. The conversion of the subordinated units did not change the aggregate amount of outstanding units, and the conversion of the subordinated units did not impact the amount of cash available for distribution by the Partnership.

Series A Preferred Units

On February 18, 2016, the Partnership completed the private placement of 14,520,000 Series A Preferred Units representing limited partner interests in the Partnership for a cash purchase price of $25.00 per Series A Preferred Unit, resulting in proceeds of $362 million, net of issuance costs. The Partnership incurred approximately $1 million of expenses related to the offering, which is shown as an offset to the proceeds. In connection with the closing of the private placement, the Partnership redeemed approximately $363 million of notes scheduled to mature in 2017 payable to a wholly-owned subsidiary of CenterPoint Energy.

Pursuant to the Partnership Agreement, the Series A Preferred Units:
rank senior to the Partnership’s common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up;
have no stated maturity;
are not subject to any sinking fund; and
will remain outstanding indefinitely unless repurchased or redeemed by the Partnership or converted into its common units in connection with a change of control.

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 to, but not including, the five year anniversary of the original issue date; and thereafter a percentage of the stated liquidation preference equal to the sum of the three-month LIBOR plus 8.5%.

At any time on or after five years after the original issue date, the Partnership may redeem the Series A Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.50 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, the Partnership (or a third-party with its prior written consent) may redeem the Series A Preferred Units following certain changes in the methodology employed by ratings agencies, changes of control or fundamental transactions as set forth in the Partnership Agreement. If, upon a change of control or certain fundamental transactions, the Partnership (or a third-party with its prior written consent) does not exercise this option, then the holders of the Series A Preferred Units have the option to convert the Series A Preferred Units into a number of common units per Series A Preferred Unit as set forth in the Partnership Agreement. The Series A Preferred Units are also required to be redeemed in certain circumstances if they are not eligible for trading on the New York Stock Exchange.

Holders of Series A Preferred Units have no voting rights except for limited voting rights with respect to potential amendments to the Partnership Agreement that have a material adverse effect on the existing terms of the Series A Preferred Units, the issuance by the Partnership of certain securities, approval of certain fundamental transactions and as required by law.

Upon the transfer of any Series A Preferred Unit to a non-affiliate of CenterPoint Energy, the Series A Preferred Units will automatically convert into a new series of preferred units (the Series B Preferred Units) on the later of the date of transfer and the second anniversary of the date of issue. The Series B Preferred Units will have the same terms as the Series A Preferred Units except that unpaid distributions on the Series B Preferred Units will accrue on a cumulative basis until paid.

On February 18, 2016, the Partnership entered into a registration rights agreement with CenterPoint Energy, pursuant to which, among other things, the Partnership gave CenterPoint Energy certain rights to require the Partnership to file and maintain a registration statement with respect to the resale of the Series A Preferred Units and any other series of preferred units or common units representing limited partner interests in the Partnership that are issuable upon conversion of the Series A Preferred Units.


ATM Program

On May 12, 2017, the Partnership entered into an ATM Equity Offering Sales Agreement in connection with an at-the-market program (the “ATM Program”). Pursuant to the ATM Program, the Partnership may issue and sell common units having an aggregate offering price of up to $200 million, by sales methods and at prices determined by market conditions and other factors at the time of our offerings. The Partnership has no obligation to sell any common units under the ATM Program and the Partnership may suspend sales under the ATM Program at any time. For the nine months ended September 30, 2017, the Partnership sold an aggregate of 18,500 common units under the ATM Program, which generated proceeds of approximately $303,000 (net of approximately $3,000 of commissions). The Partnership incurred approximately $345,000 of expenses associated with the filing of the registration statements for the ATM Program. The proceeds were used for general partnership purposes.

2016 Equity Issuance

On November 29, 2016, the Partnership closed a public offering of 10,000,000 common units at a price to the public of $14.00 per common unit. In connection with the offering, the Partnership, the underwriters and an affiliate of ArcLight entered into an underwriting agreement that provided an option for the underwriters to purchase up to an additional 1,500,000 common units, with 75,719 common units to be sold by the Partnership and 1,424,281 to be sold by the affiliate of ArcLight. The underwriters exercised the option to purchase all of the additional common units, and the Partnership received proceeds (net of underwriting discounts, structuring fees and offering expenses) of $137 million from the offering.


(5) Assessing Impairment of Long-livedLong-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 eachConstruction

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
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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 nine months ended September 30, 2016,2021 and 2020.
Three Months Ended September 30, 2021
Gathering and
Processing		Transportation
and Storage		EliminationsTotal
(In millions)
Revenues:
Product sales:
Natural gas$128 $158 $(154)$132 
Natural gas liquids485 5 (5)485 
Condensate34 — — 34 
Total revenues from natural gas, natural gas liquids, and condensate647 163 (159)651 
Loss on derivative activity(22)(6)— (28)
Total Product sales$625 $157 $(159)$623 
Service revenues:
Demand revenues$30 $110 $— $140 
Volume-dependent revenues184 12 (3)193 
Total Service revenues$214 $122 $(3)$333 
Total Revenues$839 $279 $(162)$956 
Three Months Ended September 30, 2020
Gathering and
Processing		Transportation
and Storage		EliminationsTotal
(In millions)
Revenues:
Product sales:
Natural gas$58 $77 $(68)$67 
Natural gas liquids208 2 (2)208 
Condensate15 — — 15 
Total revenues from natural gas, natural gas liquids, and condensate281 79 (70)290 
Loss on derivative activity(10)— — (10)
Total Product sales$271 $79 $(70)$280 
Service revenues:
Demand revenues$32 $116 $— $148 
Volume-dependent revenues160 10 (2)168 
Total Service revenues$192 $126 $(2)$316 
Total Revenues$463 $205 $(72)$596 
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Nine Months Ended September 30, 2021
Gathering and
Processing		Transportation
and Storage		EliminationsTotal
(In millions)
Revenues:
Product sales:
Natural gas$331 $621 $(415)$537 
Natural gas liquids1,143 13 (13)1,143 
Condensate101 — — 101 
Total revenues from natural gas, natural gas liquids, and condensate1,575 634 (428)1,781 
Loss on derivative activity(61)(10)— (71)
Total Product sales$1,514 $624 $(428)$1,710 
Service revenues:
Demand revenues$87 $344 $— $431 
Volume-dependent revenues535 46 (9)572 
Total Service revenues$622 $390 $(9)$1,003 
Total Revenues$2,136 $1,014 $(437)$2,713 
Nine Months Ended September 30, 2020
Gathering and
Processing		Transportation
and Storage		EliminationsTotal
(In millions)
Revenues:
Product sales:
Natural gas$161 $207 $(181)$187 
Natural gas liquids523 7 (7)523 
Condensate49 — — 49 
Total revenues from natural gas, natural gas liquids, and condensate733 214 (188)759 
Gain (loss) on derivative activity6 (1)— 5 
Total Product sales$739 $213 $(188)$764 
Service revenues:
Demand revenues$105 $371 $— $476 
Volume-dependent revenues487 38 (6)519 
Total Service revenues$592 $409 $(6)$995 
Total Revenues$1,331 $622 $(194)$1,759 

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 recorded an $8recognized $17 million impairmentof 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 Service Star business line,components of accounts receivable, net of allowance for doubtful accounts.
September 30, 2021December 31, 2020
(In millions)
Accounts Receivable:
Customers$385 $245 
Contract assets (1)
3 12 
Non-customers5 6 
Total Accounts Receivable (2)
$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 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.
September 30, 2021December 31, 2020
(In millions)
Deferred revenues, beginning of period (1)
$44 $48 
Amounts recognized in revenues related to the beginning balance(21)(25)
Net additions20 21 
Deferred revenues, end of period (1)
$43 $44 
____________________
(1)Deferred revenues includes deferred revenue—affiliated companies. This amount is included in Impairments onOther current liabilities and Other long-term liabilities.

The table below summarizes the timing of recognition of these contract liabilities as of September 30, 2021.
20212022202320242025 and After
(In millions)
Deferred revenues (1)
$17 $8 $8 $7 $3 
____________________
(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 and impaired substantially allIncome.
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The table below summarizes the timing of recognition of the remaining net book valueperformance obligations as of September 30, 2021.
20212022202320242025 and After
(In millions)
Transportation and Storage$114 $422 $364 $270 $1,143 
Gathering and Processing30 122 121 101 213 
Total remaining performance obligations$144 $544 $485 $371 $1,356 


(4) Leases

The table below summarizes the Service Star business line. operating leases included in the Condensed Consolidated Balance Sheets.

Balance Sheet LocationSeptember 30, 2021December 31, 2020
  (In millions)
Operating lease assetOther Assets$23 $25 
Total right-of-use assets$23 $25 
Operating lease liabilitiesOther Current Liabilities$4 $4 
Operating lease liabilitiesOther Liabilities22 24 
Total lease liabilities$26 $28 

As of 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 Service Star business line was a componentfollowing table presents the Partnership’s rental costs associated with field equipment and buildings.

Three Months Ended September 30,Nine Months Ended
September 30,
2021202020212020
(In millions)
Rental Costs:
Field equipment$2 $3 $7 $12 
Office space2 1 5 3 

As of September 30, 2021, the weighted average remaining lease term is 6.1 years and the weighted average discount rate is 5.54%.

The following table presents the Partnership’s lease cost.
Three Months Ended September 30,Nine Months Ended
September 30,
2021202020212020
(In millions)
Lease Cost:
Operating lease cost$1 $2 $4 $5 
Short-term lease cost2 2 6 9 
Variable lease cost1 — 2 1 
Total Lease Cost$4 $4 $12 $15 

All lease costs were included in the gathering and processing reportable segment that provided measurement and communication services to third parties and the impairment was primarily driven by the impact of planned technology changes affecting Service Star. The Partnership recorded no impairments to long-lived assets induring the three and nine months ended September 30, 2017. Based upon review2021 and 2020.

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Under ASC 842, as of 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$1 
20226 
20236 
20244 
20253 
20262 
After 20266 
Total28 
Less: impact of the applicable discount rate2 
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 September 30,Nine Months Ended
September 30,
2021202020212020
(In millions, except per unit data)
Net income (loss)$116 $(163)$369 $(14)
Net income (loss) attributable to noncontrolling interest— 1 2 (6)
Series A Preferred Unit distributions9 9 26 27 
Net income (loss) available to common units$107 $(173)$341 $(35)
Net income (loss) allocable to common units$107 $(173)$341 $(35)
Dilutive effect of Series A Preferred Unit distributions8 — 26 — 
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 (2)
46 — 46 — 
Dilutive effect of performance units (3)
1 — 1 — 
Diluted weighted average number of common units outstanding485 437 485 437 
Basic and diluted earnings (losses) per unit
Basic$0.24 $(0.40)$0.78 $(0.08)
Diluted$0.24 $(0.40)$0.76 $(0.08)
____________________
(1)Basic weighted average number of outstanding common units includes approximately 2000000 time-based phantom units for each of the three months ended September 30, 2021 and 2020, respectively, and 2000000 time-based phantom units for each of the nine months ended September 30, 2021 and 2020, respectively.
(2)For the three and nine months ended September 30, 2020, the issuance of “if converted” common units attributable to the Series A Preferred Units were excluded in the calculation of diluted earnings (loss) per unit as the impact was anti-dilutive.
(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 EndedRecord DatePayment DatePer Unit DistributionTotal Cash Distribution
September 30, 2021 (1)
November 8, 2021November 17, 2021$0.16525 $72 
June 30, 2021August 12, 2021August 24, 2021$0.16525 $72 
March 31, 2021May 13, 2021May 25, 2021$0.16525 $72 
December 31, 2020February 22, 2021March 1, 2021$0.16525 $72 
September 30, 2020November 17, 2020November 24, 2020$0.16525 $72 
June 30, 2020August 18, 2020August 25, 2020$0.16525 $72 
March 31, 2020May 19, 2020May 27, 2020$0.16525 $72 
_____________________
(1)The Board of Directors declared a $0.16525 per common unit cash distribution on October 26, 2021, to be paid on November 17, 2021 to common unitholders of record at the close of business on November 8, 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 EndedRecord DatePayment DateDistribution RatePer Unit DistributionTotal Cash Distribution
September 30, 2021 (1)
October 26, 2021November 12, 20218.6449 %$0.5403 $8 
June 30, 2021July 30, 2021August 13, 20218.7016 %$0.5439 $8 
March 31, 2021 (2)
April 26, 2021May 14, 20218.7375 %$0.5873 $9 
December 31, 2020February 12, 2021February 12, 202110.0 %$0.625 $9 
September 30, 2020November 3, 2020November 13, 202010.0 %$0.625 $9 
June 30, 2020August 4, 2020August 14, 202010.0 %$0.625 $9 
March 31, 2020May 5, 2020May 15, 202010.0 %$0.625 $9 
_____________________
(1)The Board of Directors declared a $0.5403 per Series A Preferred Unit cash distribution on October 26, 2021, to be paid on November 12, 2021, to Series A Preferred unitholders of record at the close of business on October 26, 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 noneattributable to the assets, as compared to the carrying value of the asset groups were at risk of failing step oneassets. Due to decreases in natural gas and NGL market prices during 2020 as a result of the ongoing COVID-19 pandemic and its economic effects, 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,
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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, test. Commoditywhich is included in Impairments of property, plant and equipment and goodwill on the Condensed Consolidated Statements of Income during the nine months ended September 30, 2020.

Impairment of Goodwill

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 throughputdue 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 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 increases, regulatory or political environment changes,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 other changesdetermined 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 market conditions could reduce forecast undiscounted cash flows.the amount of $12 million. The impairment is included in Impairments of property, plant and equipment and goodwill on the Condensed Consolidated Statements of Income for the nine months ended September 30, 2020. The Partnership had no goodwill recorded as of September 30, 2021 and December 31, 2020.




(6)(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 Spectra Energy Partners, LPEnbridge, 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, Spectra Energy Partners, LPEnbridge, Inc. may, under certain circumstances, have the right to purchase the Partnership’s interest in SESH at fair market value, subject to certain exceptions.


At September 30, 2020, the Partnership estimated the fair value of its investment in SESH was below the carrying value and concluded the decline in value was other than temporary due to the expiration of a transportation contract and the current status of renewal negotiations. As a result, the Partnership recorded a $225 million impairment on its investment in SESH for the three and nine months ended September 30, 2020, which is included in Equity in earnings (losses) of equity method affiliate, net in the Partnership’s Condensed Consolidated Statements of Income. The impairment analysis of the Partnership’s investment in SESH compared the estimated fair value of the investment to its carrying value. The fair value of the investment was determined using multiple valuation methodologies under both the market and income approaches. Due to the significant unobservable estimates and assumptions required, the Partnership concluded that the fair value estimate should be classified as a Level 3 measurement within the fair value hierarchy. The basis difference for our investment in SESH has been assigned to its property, plant and equipment and will be amortized over its approximately 50-year remaining useful life. See Note 1 for further information concerning the method used to evaluate and measure the impairment on the Partnership’s investment in SESH.

The Partnership shares operations of SESH with Spectra Energy Partners, LPEnbridge, 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 for each ofduring the three months ended September 30, 20172021 and 2016,2020, respectively, and $14$7 million and $12$11 million during the nine months ended September 30, 2017
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2021 and 2016,2020, respectively, associated with these service agreements.



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 Earningsearnings of Equity Method Affiliate:
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017
2016
 (In millions)
SESH$7
 $8
 $21
 $22

equity method affiliate recognized, Impairment of equity method affiliate investment and Distributions from Equity Method Affiliate:
equity method affiliate received.
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2017
2016 2017 2016
 (In millions)
SESH (1)
$11
 $13
 $30
 $40
Three Months Ended September 30,Nine Months Ended
September 30,
2021202020212020
(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 $7 million and $8 million return on investment and a $4 million and $5 million return of investment for the three months ended September 30, 2017 and 2016, respectively. Distributions from equity method affiliate includes a $21 million and $22 million return on investment and a $9 million and $18 million return of investment for the nine months ended September 30, 2017 and 2016, respectively.

(1)Distributions from equity method affiliate includes a $5 million and $14 million return on investment and a zero and $9 million return of investment for the nine months ended September 30, 2021 and 2020, respectively.
Summarized
The following table includes the summarized financial information of SESH:SESH.
Three Months Ended September 30,Nine Months Ended
September 30,
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		2021202020212020
2017 2016 2017 2016
(In millions)(In millions)
Income Statements:       Income Statements:
Revenues$29
 $29
 $85
 $86
Revenues$20 $24 $51 $79 
Operating income$18
 $19
 $53
 $56
Operating income8 11 14 40 
Net income$14
 $15
 $40
 $43
Net income3 6 1 27 
 

(7)
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(9) Debt

The following table presents the Partnership’s outstanding debt.
September 30, 2021December 31, 2020
Outstanding Principal
Discount (1)
Total DebtOutstanding Principal
Discount (1)
Total Debt
(In millions)
Commercial Paper$50 $— $50 $250 $— $250 
Revolving Credit Facility— — — — — — 
2019 Term Loan Agreement800 — 800 800 — 800 
2024 Notes600 — 600 600 — 600 
2027 Notes700 (1)699 700 (2)698 
2028 Notes800 (4)796 800 (5)795 
2029 Notes547 (1)546 547 (1)546 
2044 Notes531 — 531 531 — 531 
Total debt$4,028 $(6)$4,022 $4,228 $(8)$4,220 
Less: Short-term debt (2)
50 250 
Less: Current portion of long-term debt (3)
800 — 
Less: Unamortized debt expense (4)
18 19 
Total long-term debt$3,154 $3,951 
____________________
(1)Unamortized discount on long-term debt is amortized over the life of the respective debt.
(2)Short-term debt includes $50 million and $250 million of outstanding commercial paper as of September 30, 20172021 and December 31, 2016.2020, respectively.
 September 30, 2017 December 31, 2016
 Outstanding Principal Premium (Discount) Total Debt Outstanding Principal Premium (Discount) Total Debt
 (In millions)
Revolving Credit Facility$73
 $—
 $73
 $636
 $—
 $636
2015 Term Loan Agreement450
 —
 450
 450
 —
 450
2019 Notes500
 —
 500
 500
 —
 500
2024 Notes600
 —
 600
 600
 (1) 599
2027 Notes700
 (3) 697
 —
 —
 —
2044 Notes550
 —
 550
 550
 —
 550
EOIT Senior Notes250
 14
 264
 250
 18
 268
Total debt$3,123
 $11
 $3,134
 $2,986
 $17
 $3,003
Less: Current portion of long-term debt    450
     —
Less: Unamortized debt expense (1)
    15
     10
Total long-term debt    $2,669
     $2,993
____________________
(1)As of September 30, 2017 and December 31, 2016, there was an additional $3 million and $5 million, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other long-term assets, not included above.


Revolving Credit Facility

On June 18, 2015, the Partnership entered into the $1.75 billion Revolving Credit Facility, which matures on June 18, 2020, subject to an extension option, which may be exercised two times to extend the term of the Revolving Credit facility, in each case, for an additional one-year term. (3)As of September 30, 2017,2021, Current portion of long-term debt included $800 million outstanding balance of the 2019 Term Loan Agreement.
(4)As of September 30, 2021 and December 31, 2020, there were $73was an additional $2 million principal advances and $3 million, in lettersrespectively, of credit outstanding under the Revolving Credit Facility. The weighted average interest rate ofunamortized debt expense related to the Revolving Credit Facility was 2.74% as of September 30, 2017.included in Other assets, not included above.

The Revolving Credit Facility provides that outstanding borrowings bear interest at LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s applicable credit ratings. As of September 30, 2017, 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 applicable credit rating from the rating agencies. As of September 30, 2017, the commitment fee under the 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.


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 was no amountwere $50 million and $250 million outstanding under our commercial paper program at each of September 30, 20172021 and December 31, 2016. On February 2, 2016, Standard & Poor’s Ratings Services lowered its credit rating on2020, respectively. As of September 30, 2021, the Partnership from an investment grade rating to a non-investment grade rating. The short-term rating onweighted average interest rate for the Partnership was also reduced from an investment grade rating to a non-investment grade rating. As a result of the downgrade, the Partnership repaid its outstanding borrowings under the commercial paper program upon maturity and did not issue anywas 0.40%.

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 commercial paper.

Term Loan Agreement

On July 31, 2015, the Partnership entered into a Term Loan Agreement, providing for$875 million. The Revolving Credit Facility is scheduled to mature on April 6, 2023, subject to an unsecured three-year $450 million term loan agreement (2015 Term Loan Agreement). The entire $450 million principal amount of the 2015 Term Loan Agreement was borrowed by the Partnership on July 31, 2015. The 2015 Term Loan Agreement contains anextension option, which maycould be exercised up to two2 times to extend the term of the 2015 Term Loan Agreement,Revolving Credit Facility, in each case, for an additional one-year term. The 2015 Term Loan Agreement provides an option to prepay, without penalty or premium, the amount outstanding, or any portion thereof, in a minimum amount of $1 million, or any multiple of $0.5 million in excess thereof. As of September 30, 2017,2021, there were no principal advances, $3 million letters of credit outstanding and our available borrowing capacity was $450 million outstandingapproximately $1.5 billion under the 2015 Term Loan Agreement, which is included as Current portion of long-term debt in the Partnership’s Condensed Consolidated Balance Sheets.our Revolving Credit Facility.


The 2015 Term Loan AgreementRevolving 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 our applicablethe Partnership’s designated credit ratings.ratings from S&P, Moody’s and Fitch Ratings. As of September 30, 2017,2021, the applicable margin for LIBOR-based borrowings under the 2015 Term Loan AgreementRevolving Credit Facility was 1.375%1.50% based on the Partnership’s credit ratings. ForIn addition, the ninemonths endedRevolving Credit Facility requires the Partnership to pay a fee on unused commitments. The commitment fee is based on the Partnership’s credit ratings. As of September 30, 20172021, the commitment fee under the restated Revolving Credit Facility was 0.20% per annum based on the Partnership’s credit ratings. The commitment fee is recorded as interest expense in the Partnership’s Condensed Consolidated Statements of Income.

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2019 Term Loan Agreement

On January 29, 2019, the Partnership entered into an unsecured term loan agreement with Bank of America, N.A., as administrative agent, and the several lenders thereto. As of September 30, 2021, there was $800 million outstanding under the 2019 Term Loan Agreement. The 2019 Term Loan Agreement has a scheduled maturity date of January 29, 2022, but contains an option, which may be exercised up to 2 times, to extend the maturity date for an additional one-year term. The 2019 Term Loan Agreement provides that outstanding borrowings bear interest at the eurodollar rate and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s credit ratings. The applicable margin shall equal, (1) in the case of interest rates determined by reference to the eurodollar rate, between 0.75% and 1.50% per annum and (2) in the case of interest rates determined by reference to the alternate base rate, between 0% and 0.50% per annum. As of September 30, 2021, the applicable margin for LIBOR-based advances under the 2019 Term Loan Facility was 1.25% based on the Partnership’s credit ratings. As of September 30, 2021, the weighted average interest rate of the 20152019 Term Loan Agreement was 2.38%.2.06%, including the impact of the associated interest rate derivatives designated as hedging instruments for accounting purposes.


Senior Notes


On March 9, 2017, the Partnership completed the public offering of $700 million 4.400% Senior Notes due 2027 (2027 Notes). The Partnership received net proceeds of approximately $691 million. The proceeds were used for general partnership purposes, including to repay amounts outstanding under the Revolving Credit Facility. The 2027 Notes had an unamortized discount of $3 million and unamortized debt expense of $6 million at September 30, 2017, resulting in an effective interest rate of 4.58% during the nine months ended September 30, 2017.

In addition to the 2027 Notes, asAs of September 30, 2017,2021, the Partnership’s debt included the 20192024 Notes, 20242027 Notes, 2028 Notes, 2029 Notes and 2044 Notes, which had $9$6 million of unamortized discount and $18 million of unamortized debt expense at September 30, 2017,2021, resulting in effective interest rates of 2.58%4.00%, 4.02%4.56%, 5.18%, 4.30% and 5.08%, respectively, during the nine months ended September 30, 2017.


As of September 30, 2017,2021. In March 2020, the Partnership’s debt included EOIT’s $250 million 6.25% senior notes due March 2020 (the EOIT Senior Notes). The EOIT Senior Notes had $14 million of unamortized premium at September 30, 2017, resulting in an effective interest rate of 3.82%, duringmatured and were paid using proceeds from the Revolving Credit Facility.

During the nine months ended September 30, 2017.2020, the Partnership repurchased $22 million aggregate principal amount of the 2029 Notes and 2044 Notes in open market transactions for approximately $17 million plus accrued interest, which resulted in a $5 million gain on extinguishment of debt. The gain is included in Other, net in the Condensed Consolidated Statements of Income.


As of September 30, 2017,2021, the Partnership and EOIT werewas in compliance with all of theirits debt agreements, including financial covenants.



(8)(10) Derivative Instruments and Hedging Activities
 
The Partnership is exposed to certainprimary risks relating to its ongoing business operations. The primary risk managed using derivative instruments isare commodity price risk. The Partnership is also exposed to credit risk in its business operations.and interest rate risks.
Commodity Price Risk
The Partnership has used forward physical contracts, commodity price swap contracts and commodity price option features to manage the Partnership’s commodity price risk exposures in the past. Commodity derivative instruments used by the Partnership are as follows:
NGL put options, NGL futures and swaps, and WTI crude oil futures and swaps for condensate sales are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements;
natural gas futures and swaps are used to manage the Partnership’s natural gas exposure associated with its gathering, processing and transportation and storage assets; and
natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas exposure associated with its storage and transportation contracts and asset management activities.

Normal purchases and normal sales contracts are not recorded in Other Assets or Liabilities in the Condensed Consolidated Balance Sheets and earnings are recognized and recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by the Partnership’s operations and (ii) commodity contracts for the purchase and sale of NGLs produced by the Partnership’s gathering and processing business.
The Partnership recognizes its non-exchange traded derivative instruments as Other Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and, therefore, are recorded at fair value on a net basis in Other Current Assets in the Condensed Consolidated Balance Sheets.
As of September 30, 2017 and December 31, 2016, the Partnership had no derivative instruments that were designated as cash flow or fair value hedges for accounting purposes.

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

Derivatives Not Designated Asas Hedging Instruments

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



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

As of September 30, 2017 and December 31, 2016, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:purposes.

 September 30, 2017 December 31, 2016
  
Gross Notional Volume
 Purchases Sales Purchases Sales
Natural gas— TBtu(1)
       
Financial fixed futures/swaps17
 19
 2
 29
Financial basis futures/swaps19
 24
 2
 30
Physical purchases/sales1
 46
 1
 25
Crude oil (for condensate)— MBbl(2)
       
Financial Futures/swaps—
 490
 —
 540
Natural gas liquids— MBbl(3)
       
Financial Futures/swaps15
 1,701
 60
 1,133
September 30, 2021December 31, 2020
Gross Notional Volume
PurchasesSalesPurchasesSales
Natural gas— TBtu (1)
Financial fixed futures/swaps— 4 — 18 
Financial basis futures/swaps1 11 — 27 
Financial swaptions (2)
— 2 — 7 
Crude oil (for condensate)— MBbl (3)
Financial futures/swaps— 180 — 465 
Financial swaptions (2)
— 60 — 90 
Natural gas liquids— MBbl (4)
Financial futures/swaps30 300 855 1,210 
Financial options— — — 45 
____________________
(1)As of September 30, 2017, 70.8% of the natural gas contracts had durations of one year or less, 13.0% had durations of more than one year and less than two years and 16.2% had durations of more than two years. As of December 31, 2016, 100.0% of the natural gas contracts had durations of one year or less.
(2)As of September 30, 2017, 87.8% of the crude oil (for condensate) contracts had durations of one year or less and 12.2% had durations of more than one year and less than two years. As of December 31, 2016, 100% of the crude oil (for condensate) contracts had durations of one year or less.
(3)As of September 30, 2017, 79.9% of the natural gas liquids contracts had durations of one year or less and 20.1% had durations of more than one year and less than two years. As of December 31, 2016, 100% of the natural gas liquid contracts had durations of one year or less.

(1)As of September 30, 2021, 97.6% of the natural gas contracts had durations of one year or less and 2.4% 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 September 30, 2021, 93.7% of the crude oil (for condensate) contracts had durations of one year or less and 6.3% 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 September 30, 2021, 95.5% of the natural gas liquids contracts had durations of one year or less and 4.5% 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.
September 30, 2021December 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 presentedincluded in the Partnership’s Condensed Consolidated Balance Sheets that were not designated as hedging instruments for accounting purposes.
September 30, 2021December 31, 2020
  Fair Value
InstrumentBalance Sheet LocationAssetsLiabilitiesAssetsLiabilities
  (In millions)
Natural gas
Financial futures/swapsOther Current$— $13 $2 $2 
Financial swaptionsOther Current— 12 1 2 
Crude oil (for condensate)
Financial futures/swapsOther Current— 5 1 13 
Financial swaptionsOther Current— 2 — — 
Financial swaptionsOther— — — — 
Natural gas liquids
Financial futures/swapsOther Current3 9 15 3 
Financial swaptionsOther Current— — — 1 
Total gross commodity derivatives (1)
$3 $41 $19 $21 
_____________________
(1)See Note 11 for a reconciliation of the Partnership’s commodity derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of September 30, 20172021 and December 31, 20162020.

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 are as follows:purposes.
  September 30, 2017 December 31, 2016
  Fair Value
InstrumentBalance Sheet LocationAssets Liabilities Assets Liabilities
  (In millions)
Natural gas      
Financial futures/swapsOther Current/Other$4
 $3
 $2
 $22
Physical purchases/salesOther Current/Other3
 —
 —
 1
Crude oil (for condensate)        
Financial futures/swapsOther Current/Other—
 1
 —
 3
Natural gas liquids        
Financial Futures/swapsOther Current/Other—
 6
 —
 8
Total gross derivatives (1)
 $7
 $10
 $2
 $34
September 30, 2021December 31, 2020
  Fair Value
InstrumentBalance Sheet LocationAssetsLiabilitiesAssetsLiabilities
  (In millions)
Interest rate swaps (1)
Other Current$— $2 $— $6 
_____________________
(1)See Note 9 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016.

(1)All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of 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 for the three and nine months ended September 30, 2017 and 2016:Income.

Amounts Recognized in Income
Three Months Ended September 30,Nine Months Ended
September 30,
2021202020212020
(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 
  
Amounts Recognized in Income
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (In millions)
Natural gas       
Financial futures/swaps gains (losses)$1
 $6
 $17
 $(5)
Physical purchases/sales gains (losses)1
 1
 8
 (7)
Crude oil (for condensate)       
Financial futures/swaps gains (losses)(2) 1
 3
 (2)
Natural gas liquids       
Financial futures/swaps gains (losses)(7) 1
 (5) (8)
Total$(7) $9
 $23
 $(22)


For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended September 30, 20172021 and 2016,2020, 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 IncomeIncome.
Three Months Ended September 30,Nine Months Ended
September 30,
2021202020212020
 (In millions)
Change in fair value of commodity derivatives$(7)$(15)$(36)$(17)
Realized gains (losses) on commodity derivatives(21)5 (35)22 
Gains (losses) on commodity derivative activity$(28)$(10)$(71)$5 

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

Amounts Recognized in Income
Three Months Ended September 30,Nine Months Ended
September 30,
2021202020212020
(In millions)
Interest rate swaps losses$(1)$(2)$(4)$(3)

Interest rate derivatives designated as hedges are recognized in income once settled. Settlement amounts recognized in income for the three and nine monthsperiods ended September 30, 20172021 and 2016:2020 are reported in Interest expense.


 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (In millions)
Change in fair value of derivatives$(6) $8
 $29
 $(40)
Realized gain (loss) on derivatives(1) 1
 (6) 18
Gain (loss) on derivative activity$(7) $9
 $23
 $(22)

Credit-Risk Related Contingent Features in Derivative Instruments
 
Based uponIn the event Moody’s or S&P were to lower the Partnership’s senior unsecured debt rating with Moody’s Investors Services or Standard & Poor’s Ratings Services,to a below investment grade rating, the Partnership could be required to provide additional credit assurances to third parties, which could include letters of credit or cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position. As of September 30, 2017,2021, under these obligations, $1the Partnership had posted $10 million of cash collateral has been postedrelated to natural gas swaps and $1swaptions, crude oil swaps and swaptions and NGL swaps and $6 million of additional collateral maywould be required to be posted by the Partnership.Partnership in the event of a credit ratings downgrade to a below

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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.

(9)
(11) Fair Value Measurements
 
Certain assets and liabilities are recorded at fair value in the Condensed Consolidated Balance Sheets and are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities are as follows:
Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on the NYMEX and settled through a NYMEX clearing broker.
Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices

that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. Instruments classified as Level 2 include over-the-counter NYMEX natural gas swaps, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX pricing, and over-the-counter WTI crude oil swaps for condensate sales.
Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect the Partnership’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Partnership develops these inputs based on the best information available, including the Partnership’s own data.
The Partnership utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX or WTI published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX published market prices may be considered Level 1 if they are settled through a NYMEX clearing broker account with daily margining. Over-the-counter derivatives with NYMEX or WTI based prices are considered Level 2 due to the impact of counterparty credit risk. Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets that result in management’s best estimate of fair value. These contracts are classified as Level 3.
The Partnership determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the periodthree and nine months ended September 30, 2017,2021, there were no transfers between levels. As of September 30, 2021, there were no contracts classified as Level 3.
The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor’s Ratings Services and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.


Estimated Fair Value of Financial Instruments


The fair values of all accounts receivable, notes receivable, accounts payable, commercial paper and other such financial instruments on the Condensed Consolidated Balance Sheets are estimated to be approximately equivalent to their carrying amounts due to their short-term nature and have been excluded from the table below.

The following table summarizes the fair value and carrying amount of the Partnership’s financial instrumentsinstruments.
September 30, 2021December 31, 2020
Carrying AmountFair ValueCarrying AmountFair Value
(In millions)
Debt
Revolving Credit Facility (Level 2) (1)
$— $— $— $— 
2019 Term Loan Agreement (Level 2)800 800 800 800 
2024 Notes (Level 2)600 637 600 612 
2027 Notes (Level 2)699 776 698 709 
2028 Notes (Level 2)796 900 795 817 
2029 Notes (Level 2)546 593 546 544 
2044 Notes (Level 2)531 581 531 499 
____________________
(1)    Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $50 million and $250 million of commercial paper was outstanding as of September 30, 20172021 and December 31, 2016.2020, respectively.
 September 30, 2017 December 31, 2016
 Carrying Amount Fair Value Carrying Amount Fair Value
 (In millions)
Debt       
Revolving Credit Facility (Level 2)$73
 $73
 $636
 $636
2015 Term Loan Agreement (Level 2)450
 450
 450
 450
2019 Notes (Level 2)500
 498
 500
 490
2024 Notes (Level 2)600
 601
 599
 564
2027 Notes (Level 2)697
 716
 —
 —
2044 Notes (Level 2)550
 537
 550
 467
EOIT Senior Notes (Level 2)264
 266
 268
 260


The fair value of the Partnership’s Revolving Credit Facility, 20152019 Term Loan Agreement, EOIT Senior Notes, 2019 Notes, 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 September 30, 2017,2021, 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 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 supply of and demand for crude oil, NGLs and natural gas as well as the ongoing COVID-19 pandemic and its economic effects, 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
 
Fair value amounts recognized for forward,As of September 30, 2021, the Partnership’s Level 2 interest rate swap, option and other conditional or exchange contracts executedderivatives are recorded as liabilities with the same counterparty under a masterno netting arrangement may be offset. The reporting entity’s choice to offset or not must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Consolidated Balance Sheets. The Partnership has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.adjustments.

The following tables summarize the Partnership’s other assets and liabilities that are measured at fair value on a recurring basisbasis. 
September 30, 2021Commodity Contracts
Gas Imbalances (1)
AssetsLiabilities
Assets (2)
Liabilities (3)
(In millions)
Quoted market prices in active market for identical assets (Level 1)$— $11 $— $— 
Significant other observable inputs (Level 2)3 30 23 26 
Total fair value3 41 23 26 
Netting adjustments(3)(3)— — 
Total$— $38 $23 $26 
December 31, 2020Commodity Contracts
Gas Imbalances (1)
AssetsLiabilities
Assets (2)
Liabilities (3)
(In millions)
Quoted market prices in active market for identical assets (Level 1)$2 $14 $— $— 
Significant other observable inputs (Level 2)17 7 23 16 
Total fair value19 21 23 16 
Netting adjustments(19)(19)— — 
Total$— $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 September 30, 20172021 and December 31, 2016:2020.
September 30, 2017Commodity Contracts 
Gas Imbalances (1)
 Assets Liabilities 
Assets (2)
 
Liabilities (3)
 (In millions)
Quoted market prices in active market for identical assets (Level 1)$4
 $2
 $—
 $—
Significant other observable inputs (Level 2)3
 2
 14
 18
Unobservable inputs (Level 3)—
 6
 —
 —
Total fair value7
 10
 14
 18
Netting adjustments(4) (4) —
 —
Total$3
 $6
 $14
 $18

December 31, 2016Commodity Contracts 
Gas Imbalances (1)
 Assets Liabilities 
Assets (2)
 
Liabilities (3)
 (In millions)
Quoted market prices in active market for identical assets (Level 1)$2
 $22
 $—
 $—
Significant other observable inputs (Level 2)—
 4
 41
 30
Unobservable inputs (Level 3)—
 8
 —
 —
Total fair value2
 34
 41
 30
Netting adjustments—
 —
 —
 —
Total$2
 $34
 $41
 $30
______________________
(1)The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. Gas imbalances held by EOIT are valued using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices. There were no netting adjustments as of September 30, 2017 and December 31, 2016.
(2)Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $2 million and zero at September 30, 2017 and December 31, 2016,(2)Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $3 million and $19 million at 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 zero and $5 million at September 30, 2017 and December 31, 2016, 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.

Changes in Level 3 Fair Value Measurements

The following table provides a reconciliation of changes in the fair value of our Level 3 commodity contracts betweennatural gas at the periods presented.time the imbalance was created, and which are not subject to revaluation at fair market value.
 Commodity Contracts
 
Natural gas liquids
 financial futures/swaps
 (In millions)
Balance as of December 31, 2016$(8)
Losses included in earnings(5)
Settlements7
Balance as of September 30, 2017$(6)

Quantitative Information(3)Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $2 million and $3 million at September 30, 2021 and December 31, 2020, respectively, which fuel reserves are based on Level 3 Fair Value Measurements

The Partnership utilizes the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approachnatural gas at the time the imbalance was created, and which are not subject to revaluation at fair value are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in contracts.market value.



 September 30, 2017
Product GroupFair Value Forward Curve Range
 (In millions) (Per gallon)
Natural gas liquids$(6) $0.282 - $1.081


(10)(12)Supplemental Disclosure of Cash Flow Information


The following table provides information regarding supplemental cash flow information:

 Nine Months Ended September 30,
 20212020
 (In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest and debt AFUDC$112 $129 
Income taxes, net of refunds(1)1 
Non-cash transactions:
Accounts payable related to capital expenditures13 9 
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)


29
 Nine Months Ended 
 September 30,
 2017 2016
 (In millions)
Supplemental Disclosure of Cash Flow Information:   
Cash Payments:   
Interest, net of capitalized interest$77
 $67
Income taxes, net of refunds—
 1
Non-cash transactions:

 

Accounts payable related to capital expenditures52
 32


The following table reconciles cash and cash equivalents and restricted cash on the Condensed Consolidated Balance Sheets to cash, cash equivalents and restricted cash on the Condensed Consolidated StatementTable of Cash Flows:
Contents
 Nine Months Ended 
 September 30,
 2017 2016
 (In millions)
Cash and cash equivalents$8
 $23
Restricted cash14
 —
Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows$22
 $23


(11)(13) Related Party Transactions
 
The material related party transactions with CenterPoint Energy, OGE Energy and their respective subsidiaries are summarized below. There were no material related party transactions with other affiliates.
Transportation and Storage Agreements

Transportation and Storage Agreements with CenterPoint Energy
EGT provides the following services to CenterPoint Energy’s LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas: (1) firm transportation with seasonal contract demand, (2) firm storage, (3) no notice transportation with associated storage and (4) maximum rate firm transportation. The first three services are in effect through March 31, 2021, and will remain in effect from year to year thereafter unless either party provides 180 days’ written notice prior to the contract termination date. The maximum rate firm transportation is in effect through March 31, 2018. MRT provides firm transportation and firm storage services to CenterPoint Energy’s LDCs under agreements that are in effect through May 15, 2023, but will continue year to year thereafter unless either party provides twelve months’ written notice prior to the contract termination date.

Transportation and Storage Agreement with OGE Energy
EOIT provides no-notice load-following transportation and storage services to OGE Energy. On March 17, 2014, EOIT entered into a transportation agreement with OGE Energy, with a primary term of May 1, 2014 through April 30, 2019. Following the primary term, the agreement will remain in effect from year to year thereafter unless either party provides notice of termination to the other party at least 180 days prior to the commencement of the succeeding annual period.

On December 6, 2016, EOIT entered into a transportation agreement with OGE Energy, with a primary term expected to begin in late 2018 and extend for 20 years. In connection with the agreement, an approximately 80-mile pipeline will be built to expand the EOIT system.

Gas Sales and Purchases Transactions

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


The Partnership’s revenues from affiliated companies accounted for 5% and 6% of total revenues during the three months ended September 30, 2017 and 2016, respectively, and 5% and 7% of total revenues during the nine months ended September 30, 20172021 and 2016,2020, respectively. AmountsThe following table presents the amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows:Income.
 
Three Months Ended September 30,Nine Months Ended
September 30,
2021202020212020
(In millions)
Gas transportation and storage service revenues — CenterPoint Energy$15 $17 $58 $76 
Natural gas product sales — CenterPoint Energy— — 5 1 
Gas transportation and storage service revenues — OGE Energy10 9 29 28 
Natural gas product sales — OGE Energy
1 4 34 9 
Total revenues — affiliated companies$26 $30 $126 $114 
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (In millions)
Gas transportation and storage service revenue — CenterPoint Energy$22
 $22
 $79
 $79
Natural gas product sales — CenterPoint Energy—
 —
 1
 1
Gas transportation and storage service revenue — OGE Energy9
 10
 27
 28
Natural gas product sales — OGE Energy 
2
 4
 2
 10
Total revenues — affiliated companies$33
 $36
 $109
 $118


AmountsThe following table presents the amounts of natural gas purchased from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows:Income.
Three Months Ended September 30,Nine Months Ended
September 30,
2021202020212020
(In millions)
Cost of natural gas purchases — CenterPoint Energy$— $— $— $1 
Cost of natural gas purchases — OGE Energy13 6 56 20 
Total cost of natural gas purchases — affiliated companies$13 $6 $56 $21 

 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (In millions)
Cost of natural gas purchases — CenterPoint Energy$—
 $—
 $1
 $—
Cost of natural gas purchases — OGE Energy6
 4
 13
 9
Total cost of natural gas purchases — affiliated companies$6
 $4
 $14
 $9

Seconded employee, corporateCorporate services and operating lease expenseseconded 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 September 30, 20172021, 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 $5 million in 2017 and at actual cost subject to aan annual cap of $5 million in 2018 and thereafter, unless and until secondment is terminated.
 
UnderThe following table presents the terms of the MFA, the Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under service agreements for an initial term that ended on April 30, 2016. The service agreements automatically extend year-to-year at the end of the initial term, unless terminated by the Partnership with at least 90 days’ notice prior to the end of any extension. Additionally, the Partnership may terminate these service agreements at any time with 180 days’ notice, if approved by the Board of Enable GP. The Partnership reimburses CenterPoint Energy and OGE Energy for these services up to annual caps, which for 2017 are $3 million and $4 million, respectively.

On November 1, 2016, the Partnership entered into a new lease with an affiliate of CenterPoint Energy pursuant to which the Partnership leases office space in Shreveport, Louisiana. The term of the lease was effective on October 1, 2016 and extends through December 31, 2019. The Partnership expects to incur approximately $3 million in rent and maintenance expenses through the end of the initial term of the lease. Prior to October 1, 2016, CenterPoint Energy provided the office space in Shreveport, Louisiana, under the services agreement. As of September 30, 2017, CenterPoint Energy continues to provide office and data center space to the Partnership in Houston, Texas, under the services agreement.


Amountsamounts charged to the Partnership by affiliates for seconded employees, an operating lease and corporate services, included primarily in Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income are as follows:Income.
 
Three Months Ended September 30,Nine Months Ended
September 30,
2021202020212020
(In millions)
Seconded Employee Costs — OGE Energy$4 $5 $11 $13 






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 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (In millions)
Corporate Services — CenterPoint Energy$—
 $1
 $2
 $6
Operating Lease — CenterPoint Energy1
 —
 1
 —
Seconded Employee Costs — OGE Energy7
 5
 23
 22
Corporate Services — OGE Energy1
 1
 3
 4
Total corporate services and seconded employees expense$9

$7
 $29
 $32

Series A Preferred Units

On February 18, 2016, the Partnership completed the private placement, with CenterPoint Energy, of 14,520,000 Series A Preferred Units representing limited partner interests in the Partnership for a cash purchase price of $25.00 per Series A Preferred Unit, resulting in proceeds of $362 million, net of issuance costs. See Note 4 for further discussion of the Series A Preferred Units.

Notes payable

On February 18, 2016, in connection with the private placement of the Series A Preferred Units, the Partnership redeemed $363 million of notes payable—affiliated companies payable to a subsidiary of CenterPoint Energy. As of September 30, 2017, the Partnership has not had any notes payable to any affiliate and has not incurred interest expense to any affiliate since February 18, 2016.


(12)(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 September 30, 2021, the Partnership estimates the remaining associated minimum volume commitment fee to be $153 million. Minimum volume commitment fees are expected to be $4 million for the remainder of 2021, $23 million per year from 2022 through 2027 and $11 million in 2028.

(13)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 of 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 for the three and nine months ended September 30, 2017 and 2016 related to performance units, restricted units and phantom units for the Partnership’s employees and independent directors:directors.

Three Months Ended September 30,Nine Months Ended
September 30,
2021202020212020
(In millions)
Performance units$3 $1 $7 $5 
Phantom units1 2 5 5 
Total compensation expense$4 $3 $12 $10 

The following table presents the assumptions related to the performance units granted in 2021.
2021
Number of units granted1,453,897
Fair value of units granted$10.26 
Expected distribution yield12.90 %
Expected price volatility100.00 %
Risk-free interest rate0.27 %
Expected life of units (in years)3

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Table of Contents
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (In millions)
Performance units$3
 $4
 $8
 $7
Restricted units—
 1
 1
 2
Phantom units1
 —
 3
 1
Total compensation expense$4
 $5
 $12
 $10
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 granted1,371,001 
Fair value of phantom units granted$5.41 - $6.87


Units Outstanding


The Partnership periodically grants performance units, restricted units, and phantom units to certain employees under the Enable Midstream Partners, LP Long Term Incentive Plan. A summary of the activity for the Partnership’s performance units, restricted units and phantom units applicable to the Partnership’s employees at September 30, 20172021 and changes during 20172021 are shown in the following table.

 Performance Units Restricted Units Phantom Units
  
Number
of Units
 Weighted Average Grant-Date Fair Value, Per Unit 
Number
of Units
 Weighted Average Grant-Date Fair Value, Per Unit 
Number
of Units
 Weighted Average Grant-Date Fair Value, Per Unit
 (In millions, except unit data)
Units Outstanding at December 31, 20161,969,107
 $15.27
 392,995
 $20.74
 643,604
 $8.49
Granted(1)
468,626
 19.27
 —
 —
 389,209
 16.24
Vested(2)
(334,682) 29.61
 (149,169) 25.47
 (15,937) 13.18
Forfeited(42,150) 14.93
 (8,666) 19.07
 (19,799) 11.42
Units Outstanding at September 30, 20172,060,901
 $13.86
 235,160
 $17.81
 997,077
 $11.38
 Aggregate Intrinsic Value of Units Outstanding at September 30, 2017$33
   $4
   $16
  
Performance UnitsPhantom Units
Number
of Units		Weighted Average Grant-Date Fair Value, Per UnitNumber
of Units		Weighted Average Grant-Date Fair Value, Per Unit
(In millions, except unit data)
Units outstanding at December 31, 20201,765,508 $13.10 1,790,845 $10.29 
Granted (1)
1,453,897 10.26 1,371,001 6.86 
Vested (2)
(398,614)17.70 (485,662)13.08 
Forfeited(45,945)9.94 (139,975)8.52 
Units outstanding at September 30, 20212,774,846 $11.00 2,536,209 $7.99 
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 percent to 200 percent of the target.
(2)Performance units vested as of September 30, 2017 include 334,682 units from the annual grant, which were approved by the Board of Directors in 2014 and paid out at 91.5%, or 306,170 units, based on the level of achievement of a performance goal established by the Board of Directors over the performance period.

(1)Performance units represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from 0% to 200% of the target.
(2)Performance units vested as of September 30, 2021 include 398,614 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


A summary ofThe following table summarizes the Partnership’s unrecognized compensation cost for its non-vested performance units, restricted units and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.recognized.
September 30, 2021
Unrecognized Compensation Cost
(In millions)		Weighted Average Period for Recognition
(In years)
Performance Units$16 1.76
Phantom Units10 1.61
Total$26 
 September 30, 2017
 
Unrecognized Compensation Cost
(In millions)
 
Weighted Average to be Recognized
(In years)
Performance Units$15
 1.54
Restricted Units1
 0.68
Phantom Units8
 1.83
Total$24
  


As of September 30, 2017,2021, there were 8,656,0353,151,858 units available for issuance under the long termlong-term incentive plan.




(14)
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Table of Contents
(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 2016 consolidated financial statements2020 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 two2 reportable segments: (i) gathering and processing whichand (ii) transportation and storage. Our gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers and

(ii) crude oil, condensate and produced water gathering services to our producer and refiner customers. The transportation and storage whichsegment provides interstate and intrastate natural gas pipeline transportation and storage serviceservices primarily to our producer, power plant, LDC and industrial end-user customers.



33
Table of Contents
Financial data for reportable segments are as follows:

Three Months Ended September 30, 2021Gathering and
Processing
Transportation (1)
and Storage
EliminationsTotal
 (In millions)
Product sales$625 $157 $(159)$623 
Service revenues214 122 (3)333 
Total Revenues839 279 (162)956 
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)571 154 (160)565 
Operation and maintenance, General and administrative77 43 (1)119 
Depreciation and amortization74 30 — 104 
Taxes other than income tax10 6 — 16 
Operating income$107 $46 $(1)$152 
Total Assets$10,953 $6,130 $(5,303)$11,780 
Capital expenditures (excluding equity AFUDC)$27 $26 $— $53 
Three Months Ended September 30, 2020Gathering and
Processing
Transportation (1)
and Storage
EliminationsTotal
 (In millions)
Product sales$271 $79 $(70)$280 
Service revenues192 126 (2)316 
Total Revenues463 205 (72)596 
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)244 78 (72)250 
Operation and maintenance, General and administrative77 47 — 124 
Depreciation and amortization75 30 — 105 
Taxes other than income tax10 7 — 17 
Operating income$57 $43 $— $100 
Total assets as of December 31, 2020$10,830 $5,729 $(4,830)$11,729 
Capital expenditures (excluding equity AFUDC)$21 $29 $— $50 
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Table of Contents
Three Months Ended September 30, 2017Gathering and
Processing		 
Transportation
and Storage(1)
 Eliminations Total
 (In millions)
Product sales$357
 $152
 $(113) $396
Service revenue185
 125
 (1) 309
Total Revenues542
 277
 (114) 705
Cost of natural gas and natural gas liquids308
 154
 (113) 349
Operation and maintenance, General and administrative70
 45
 (1) 114
Depreciation and amortization56
 34
 —
 90
Taxes other than income tax9
 6
 —
 15
Operating income$99
 $38
 $—
 $137
Total assets$8,749
 $5,560
 $(3,047) $11,262
Capital expenditures$86
 $16
 $—
 $102
        
        
Three Months Ended September 30, 2016Gathering and
Processing		 

Transportation
and Storage(1)
 Eliminations Total
 (In millions)
Product sales$295
 $150
 $(119) $326
Service revenue160
 135
 (1) 294
Total Revenues455
 285
 (120) 620
Cost of natural gas and natural gas liquids246
 141
 (119) 268
Operation and maintenance, General and administrative63
 46
 (1) 108
Depreciation and amortization53
 31
 —
 84
Impairments8
 —
 —
 8
Taxes other than income tax8
 5
 —
 13
Operating income$77
 $62
 $—
 $139
Total assets as of December 31, 2016$7,453
 $4,963
 $(1,204) $11,212
Capital expenditures$52
 $16
 $—
 $68

Nine Months Ended September 30, 2021Nine Months Ended September 30, 2021Gathering and
Processing
Transportation (1)
and Storage
EliminationsTotal
(In millions)
Nine Months Ended September 30, 2017Gathering and
Processing		 
Transportation
and Storage(1)
 Eliminations Total
Product salesProduct sales$1,514 $624 $(428)$1,710 
Service revenuesService revenues622 390 (9)1,003 
Total RevenuesTotal Revenues2,136 1,014 (437)2,713 
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)1,406 539 (435)1,510 
Operation and maintenance, General and administrativeOperation and maintenance, General and administrative229 129 (2)356 
Depreciation and amortizationDepreciation and amortization222 91 — 313 
Taxes other than income taxTaxes other than income tax32 20 — 52 
Operating incomeOperating income$247 $235 $— $482 
Total AssetsTotal Assets$10,953 $6,130 $(5,303)$11,780 
Capital expenditures (excluding equity AFUDC)Capital expenditures (excluding equity AFUDC)$68 $136 $— $204 
Nine Months Ended September 30, 2020Nine Months Ended September 30, 2020Gathering and
Processing
Transportation (1)
and Storage
EliminationsTotal
(In millions) (In millions)
Product sales$1,044
 $439
 $(347) $1,136
Product sales$739 $213 $(188)$764 
Service revenue469
 395
 (3) 861
Service revenuesService revenues592 409 (6)995 
Total Revenues1,513
 834
 (350) 1,997
Total Revenues1,331 622 (194)1,759 
Cost of natural gas and natural gas liquids863
 421
 (348) 936
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)631 215 (193)653 
Operation and maintenance, General and administrative215
 135
 (2) 348
Operation and maintenance, General and administrative250 137 (1)386 
Depreciation and amortization167
 100
 —
 267
Depreciation and amortization223 91 — 314 
Impairments of property, plant and equipment and goodwillImpairments of property, plant and equipment and goodwill28 — — 28 
Taxes other than income tax27
 20
 —
 47
Taxes other than income tax32 20 — 52 
Operating income$241
 $158
 $—
 $399
Operating income$167 $159 $— $326 
Total assets$8,749
 $5,560
 $(3,047) $11,262
Capital expenditures$176
 $74
 $—
 $250
       
       
Nine Months Ended September 30, 2016Gathering and
Processing		 

Transportation
and Storage(1)
 Eliminations Total
(In millions)
Product sales$759
 $348
 $(270) $837
Service revenue416
 408
 (3) 821
Total Revenues1,175
 756
 (273) 1,658
Cost of natural gas and natural gas liquids642
 346
 (271) 717
Operation and maintenance, General and administrative205
 140
 (2) 343
Depreciation and amortization154
 94
 —
 248
Impairments8
 —
 —
 8
Taxes other than income tax24
 19
 —
 43
Operating income$142
 $157
 $—
 $299
Total assets as of December 31, 2016$7,453
 $4,963
 $(1,204) $11,212
Capital expenditures$252
 $37
 $—
 $289
Total assets as of December 31, 2020Total assets as of December 31, 2020$10,830 $5,729 $(4,830)$11,729 
Capital expenditures (excluding equity AFUDC)Capital expenditures (excluding equity AFUDC)$79 $73 $— $152 
_____________________
(1)See Note 6
(1)See Note 8 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and nine months ended September 30, 2017 and 2016.


(15) Subsequent Event

On October 4, 2017, the Partnership acquired all of the equity interests in Align Midstream, LLC, a midstream company with natural gas gatheringSESH and processing facilitiesrelated equity earnings included in the Cotton Valleytransportation and Haynesville playsstorage segment for the three and nine months ended September 30, 2021 and 2020.



35
Table of the Ark-La-Tex Basin, for approximately $300 million, subject to certain post-closing adjustments. The acquisition will be treated as a business combination and was funded with borrowings under the Revolving Credit Facility. Due to the timing of the acquisition, the Partnership has not yet completed its initial accounting analysis. As a result, the Partnership is unable to provide amounts recognized as of the acquisition date for major classes of assets and liabilities acquired and resulting from the transaction, including any intangible assets or goodwill.Contents


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 statementsCondensed Consolidated Financial Statements and the related notes included herein and our audited consolidated financial statementsConsolidated Financial Statements for the year ended December 31, 2016,2020, 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.control, including risks resulting from the ongoing COVID-19 pandemic and its economic effects. Our actual results could differ materially from those discussed in these forward-looking statements. Please read “Forward-Looking Statements.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.


Overview


Enable Midstream Partners, LP is a Delaware limited partnership formed in May 2013 by CenterPoint Energy, OGE Energyowns, operates and ArcLight to own, operate and developdevelops midstream energy infrastructure assets strategically located to serve our customers. We completed our IPO in April 2014, and 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 Bakken Shale formation of theAnadarko and Williston Basin.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, aan 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. 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, and growing through accretive acquisitions, maintaining strong customer relationships to attract new volumes and disciplined development.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 the development of 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.


Typically, we do not announce a transaction until after we have executed a definitive agreement. However, in certain cases in order
Liquidity and Capital Resources

The Partnership’s principal liquidity requirements are to protectfinance its operations, fund capital expenditures and acquisitions, make cash distributions and satisfy any indebtedness obligations. We expect that our business interests or forliquidity and capital resource needs will be met by our sources of liquidity, which as of 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 reasons, we may defer public announcement of a transaction until closing or a later date. Past experience has demonstrated that the pace of discussionsoutstanding debt agreements and negotiations regarding potential transactions is unpredictablepreferred equity, please see Note 6 “Partners’ Equity” and can advance or terminate in a short period of time.


Recent Developments

Acquisition of Align Midstream

On October 4, 2017, the Partnership completed the acquisition of Align Midstream, LLC, a midstream company with natural gas gathering and processing facilitiesNote 9 “Debt” in the Cotton ValleyNotes to the Unaudited Condensed Consolidated Financial Statements under Item 1. “Financial Statements.”

Cash on hand and Haynesville playsoperating 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
36
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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 September 30, 2021, we had a working capital deficit of $763 million. The deficit is primarily due to the classification of $800 million of the Ark-La-Tex Basin, for approximately $3002019 Term Loan Agreement as Current portion of long-term debt as of September 30, 2021 as well as $50 million subjectof commercial paper outstanding as of September 30, 2021.We utilize our commercial paper program and Revolving Credit Facility to certain customary post-closing adjustments. The acquisition includes approximately 190 milesmanage the timing of natural gas gathering pipelines across Rusk, Panolacash flows and Shelby counties in Texas and DeSoto Parish in Louisiana and a cryogenic natural gas processing plant in Panola County, Texas, with a capacity of 100 MMcf/d. These assets are underpinned with long-term, fee-based contracts, including approximately 100,000 gross acres of dedication from producer customers.fund short-term working capital deficits.
 

Cash Flows
ATM Program

The following tables reflect cash flows for the applicable periods.
On May 12, 2017, the Partnership entered into an ATM Equity Offering Sales Agreement
 Nine Months Ended September 30,
 20212020
 (In millions)
Net cash provided by operating activities$678 $543 
Net cash used in investing activities(198)(120)
Net cash used in financing activities(447)(409)
Operating Activities
The increase of $135 million, or 25%, in connection with an at-the-market program (the “ATM Program”). Pursuant to the ATM Program, the Partnership may issue and sell common units having an aggregate offering price of up to $200 million,net cash provided by sales methods and at prices determined by market conditions and other factors at the time of our offerings. The Partnership has no obligation to sell any common units under the ATM Program and the Partnership may suspend sales under the ATM Program at any time. Foroperating activities for the nine months ended September 30, 2017,2021 as compared to the Partnership soldnine months ended September 30, 2020 was primarily driven by an aggregateincrease in net income of 18,500$383 million and an increase of $22 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 $270 million.

Investing Activities
The increase of $78 million, or 65%, in net cash used in investing activities for the nine months ended September 30, 2021 as compared to the nine months ended September 30, 2020 was primarily due to higher capital expenditures of $52 million, a decrease in return of investment in equity method affiliate of $9 million and a decrease in proceeds from sale of assets of $16 million.

Financing Activities

Net cash used in financing activities increased $38 million, or 9%, for the nine months ended September 30, 2021 as compared to the nine months ended September 30, 2020. Our primary financing activities consist of the following:

Nine Months Ended September 30,
20212020
(In millions)
Increase (decrease) in short-term debt$(200)$179 
Repayment of EOIT Senior Notes— (250)
Repurchase of 2029 Senior Notes and 2044 Senior Notes— (17)
Distributions(245)(320)
Cash paid for employee equity-based compensation(2)(1)

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Distributions
On October 26, 2021, the Board of Directors declared a quarterly cash distribution of $0.16525 per common unit on all of the Partnership’s outstanding common units underfor the ATM Program, which generated proceedsperiod ended September 30, 2021. The distributions will be paid November 17, 2021 to unitholders of approximately $303,000 (net of approximately $3,000 of commissions). The Partnership incurred approximately $345,000 of expenses associated with the filingrecord as of the registration statements forclose of business on November 8, 2021. Additionally, the ATM Program.Board of Directors declared a quarterly cash distribution of $0.5403 on the Partnership’s outstanding Series A Preferred Units. The proceeds were used for general partnership purposes. distributions will be paid November 12, 2021 to unitholders of record as of the close of business on October 26, 2021.


IssuanceTrends 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 Senior Notes

On March 9, 2017,consolidated funded indebtedness to consolidated earnings before interest, taxes, depreciation and amortization as of the Partnership completed the public offeringlast day of $700 million 4.400% Senior Noteseach fiscal quarter of less than or equal to 5.00 to 1.00. As of September 30, 2021, our available borrowing capacity under our Revolving Credit Facility was approximately $1.5 billion due 2027 (2027 Notes). The Partnership received net proceeds of approximately $691 million. The proceeds were used for general partnership purposes, including to repaythis financial covenant, prior to invoking any amounts outstanding underrelated to Qualified Project EBITDA Adjustments (as defined in the Revolving Credit Facility.Facility). We believe that we will have sufficient cash flow and borrowing capacity to fully fund our business.


Commercial
Results of Operations

Trends and Construction UpdateUncertainties Affecting Results of Operations


Project Wildcat rich gas takeaway solution

The Partnership has entered into an agreement to deliver approximately 400 MMcf/d of rich natural gas from the Anadarko Basin to north Texas, providing a new market outlet for growing Anadarko Basin production. Project Wildcat is expected to provide access to the Texas intrastate natural gas markets, including the Tolar Hub, by contracting with an affiliate of Energy Transfer Partners, LP for 400 MMcf/d of firm processing capacity at the Godley Plant in Johnson County, Texas. The project is expected to be in service by the end of the second quarter of 2018. Even with the 400 MMcf/d of processing capacity provided by this project, the Partnership anticipates that there will be a need to resume construction of the previously announced Wildhorse Plant, though likely not before 2019.Merger


EGT Expansion Project

In March 2017, EGT conducted a non-binding open season to solicit commitments for the Cana and STACK Expansion (CaSE) project, a system expansion providing firm transportation service for growing Anadarko Basin production. The project’s foundation shipper, Newfield Exploration Company, hasOn February 16, 2021, we entered into a 205,000 Dth/d firm natural gas transportation agreementdefinitive Merger Agreement with EGT. The 10-year contract is expectedEnergy Transfer, pursuant to start atwhich, among other things, all outstanding common units of the Partnership will be acquired by Energy Transfer in an initial capacityall-equity transaction, including the assumption of 45,000 Dth/d in early 2018debt and growother liabilities, subject to the full contracted capacityconditions 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, and 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 fourth quarter of 2018.2021. 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.


CenterPoint Strategic Review
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COVID-19 Pandemic
As previously disclosed, CenterPoint Energy
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 nine months ended September 30, 2021 as compared to the nine months ended September 30, 2020, our revenues and gross margin increased. These increases resulted, 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. 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 stormand 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.

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.

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 announcednot 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 evaluating strategic alternativeslimited to criminal law as applied within the Muscogee (Creek) Nation reservation, the ruling has significant potential implications for its investmentcivil law within the Muscogee (Creek) Nation reservation, as well as other reservations in Enable. CenterPoint Energy has disclosedOklahoma 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 alternatives may include a saleCherokee, Chickasaw, Seminole and Choctaw reservations likewise have not been disestablished. On October 1, 2020, the EPA granted approval to the State of all or a portionOklahoma under Section 10211(a) of the interests that it owns in Enable and Enable GP, that if the sale option is not viable it intendsSafe, Accountable, Efficient Transportation Equity Act of 2005 (the “SAFETE Act”) to reduce its ownership in Enable over time through a saleadminister all of the Enable common units it holdsState’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.

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 public equity markets subjectMuscogee (Creek) Nation’s lands. The State of Oklahoma
has petitioned the U.S. Supreme Court to market conditions,overturn this determination and find that there canMcGirt 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 no assurancesresolved.

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, these evaluationsamong 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 appealed the ruling on August 16, 2021 to the U.S. Court of Appeals for the 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, inwe may incur significant additional costs to comply with the pending regulations, and any specific action.other future laws and regulations, which could have a material impact on our costs of and revenues from operations.



FERC Update


ResultsOn February 18, 2021, FERC issued a renewed Notice of OperationsInquiry (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 operationsoperations.
Three Months Ended September 30, 2021Gathering and
Processing		Transportation
and Storage		EliminationsEnable
Midstream
Partners, LP
 (In millions)
Product sales$625 $157 $(159)$623 
Service revenues214 122 (3)333 
Total Revenues839 279 (162)956 
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)571 154 (160)565 
Gross margin (1)
268 125 (2)391 
Operation and maintenance, General and administrative77 43 (1)119 
Depreciation and amortization74 30 — 104 
Taxes other than income tax10 6 — 16 
Operating income$107 $46 $(1)$152 
Three Months Ended September 30, 2020Gathering and
Processing		Transportation
and Storage		EliminationsEnable
Midstream
Partners, LP
 (In millions)
Product sales$271 $79 $(70)$280 
Service revenues192 126 (2)316 
Total Revenues463 205 (72)596 
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)244 78 (72)250 
Gross margin (1)
219 127 — 346 
Operation and maintenance, General and administrative77 47 — 124 
Depreciation and amortization75 30 — 105 
Taxes other than income tax10 7 — 17 
Operating income$57 $43 $— $100 
Nine Months Ended September 30, 2021Gathering and
Processing		Transportation
and Storage		EliminationsEnable
Midstream
Partners, LP
 (In millions)
Product sales$1,514 $624 $(428)$1,710 
Service revenues622 390 (9)1,003 
Total Revenues2,136 1,014 (437)2,713 
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)1,406 539 (435)1,510 
Gross margin (1)
730 475 (2)1,203 
Operation and maintenance, General and administrative229 129 (2)356 
Depreciation and amortization222 91 — 313 
Taxes other than income tax32 20 — 52 
Operating income$247 $235 $— $482 
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Nine Months Ended September 30, 2020Gathering and
Processing		Transportation
and Storage		EliminationsEnable
Midstream
Partners, LP
 (In millions)
Product sales$739 $213 $(188)$764 
Service revenues592 409 (6)995 
Total Revenues1,331 622 (194)1,759 
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)631 215 (193)653 
Gross margin (1)
700 407 (1)1,106 
Operation and maintenance, General and administrative250 137 (1)386 
Depreciation and amortization223 91 — 314 
Impairments of property, plant and equipment and goodwill28 — — 28 
Taxes other than income tax32 20 — 52 
Operating income$167 $159 $— $326 
_____________________
(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 September 30,Nine Months Ended
September 30,
 2021202020212020
Operating Data:
Natural gas gathered volumes—TBtu402 3741,169 1,164 
Natural gas gathered volumes—TBtu/d4.37 4.074.28 4.25 
Natural gas processed volumes—TBtu (1)
208 190593 597 
Natural gas processed volumes—TBtu/d (1)
2.26 2.062.17 2.18 
NGLs produced—MBbl/d (1)(2)
141.46 133.11135.41 122.29 
NGLs sold—MBbl/d (2)(3)
143.32 138.55137.02 127.66 
Condensate sold—MBbl/d5.80 5.586.44 6.50 
Crude oil and condensate gathered volumes—MBbl/d97.7 138.02107.30 121.38 
Transported volumes—TBtu491 4401,539 1,532 
Transported volumes—TBtu/d5.33 4.785.62 5.58 
Interstate firm contracted capacity—Bcf/d5.62 5.735.96 6.00 
Intrastate average deliveries—TBtu/d1.69 1.741.64 1.83 
 _____________________
(1)Includes volumes under third-party processing arrangements.
(2)Excludes condensate.
(3)NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for the threesystem balancing purposes.
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Three Months Ended September 30,Nine Months Ended
September 30,
 2021202020212020
Anadarko
Gathered volumes—TBtu/d2.18 1.942.10 2.04 
Natural gas processed volumes—TBtu/d (1)
1.98 1.761.89 1.85 
NGLs produced—MBbl/d (1)(2)
127.71 120.80122.91 109.29 
Crude oil and condensate gathered volumes—MBbl/d70.36 104.9376.99 93.65 
Arkoma
Gathered volumes—TBtu/d0.40 0.410.40 0.42 
Natural gas processed volumes—TBtu/d (1)
0.07 0.080.07 0.08 
NGLs produced—MBbl/d (1)(2)
4.76 3.944.25 3.96 
Ark-La-Tex
Gathered volumes—TBtu/d1.79 1.721.78 1.79 
Natural gas processed volumes—TBtu/d0.21 0.220.21 0.25 
NGLs produced—MBbl/d (2)
8.99 8.378.25 9.04 
Williston
Crude oil gathered volumes—MBbl/d27.35 33.0930.31 27.73 
 _____________________
(1)Includes volumes under third-party processing arrangements.
(2)Excludes condensate.

Gathering and nineProcessing

Three months ended September 30, 2017 and 2016.

Three Months Ended September 30, 2017Gathering and
Processing		 Transportation
and Storage		 Eliminations Enable
Midstream
Partners, LP
 (In millions)
Product sales$357
 $152
 $(113) $396
Service revenue185
 125
 (1) 309
Total Revenues542
 277
 (114) 705
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)308
 154
 (113) 349
Gross margin (1)
234
 123
 (1) 356
Operation and maintenance, General and administrative70
 45
 (1) 114
Depreciation and amortization56
 34
 —
 90
Taxes other than income tax9
 6
 —
 15
Operating income$99
 $38
 $—
 $137
Equity in earnings of equity method affiliate$—
 $7
 $—
 $7

Three Months Ended September 30, 2016Gathering and
Processing		 Transportation
and Storage		 Eliminations Enable
Midstream
Partners, LP
 (In millions)
Product sales$295
 $150
 $(119) $326
Service revenue160
 135
 (1) 294
Total Revenues455
 285
 (120) 620
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)246
 141
 (119) 268
Gross margin (1)
209
 144
 (1) 352
Operation and maintenance, General and administrative63
 46
 (1) 108
Depreciation and amortization53
 31
 —
 84
Impairments8
 —
 —
 8
Taxes other than income tax8
 5
 —
 13
Operating income$77
 $62
 $—
 $139
Equity in earnings of equity method affiliate$—
 $8
 $—
 $8



Nine Months Ended September 30, 2017Gathering and
Processing		 Transportation
and Storage		 Eliminations Enable
Midstream
Partners, LP
 (In millions)
Product sales$1,044
 $439
 $(347) $1,136
Service revenue469
 395
 (3) 861
Total Revenues1,513
 834
 (350) 1,997
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)863
 421
 (348) 936
Gross margin (1)
650
 413
 (2) 1,061
Operation and maintenance, General and administrative215
 135
 (2) 348
Depreciation and amortization167
 100
 —
 267
Taxes other than income tax27
 20
 —
 47
Operating income$241
 $158
 $—
 $399
Equity in earnings of equity method affiliate$—
 $21
 $—
 $21
Nine Months Ended September 30, 2016
Gathering and
Processing
 
Transportation
and Storage
 Eliminations 
Enable
Midstream
Partners, LP
 (In millions)
Product sales$759
 $348
 $(270) $837
Service revenue416
 408
 (3) 821
Total Revenues1,175
 756
 (273) 1,658
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)642
 346
 (271) 717
Gross margin (1)
533
 410
 (2) 941
Operation and maintenance, General and administrative205
 140
 (2) 343
Depreciation and amortization154
 94
 —
 248
Impairments8
 —
 —
 8
Taxes other than income tax24
 19
 —
 43
Operating income$142
 $157
 $—
 $299
Equity in earnings of equity method affiliate$—
 $22
 $—
 $22
_____________________
(1)Gross margin is a non-GAAP measure and is reconciled to its most directly comparable financial measures calculated and presented below under the caption Reconciliations of Non-GAAP Financial Measures.



 Three Months Ended 
 September 30,
Nine Months Ended 
 September 30,
 2017
2016
2017
2016
Operating Data:
Gathered volumes—TBtu325

291

922

851
Gathered volumes—TBtu/d3.52

3.16

3.38

3.11
Natural gas processed volumes—TBtu174

164

516

487
Natural gas processed volumes—TBtu/d1.90

1.78

1.89

1.78
NGLs produced—MBbl/d(1)
84.48

77.53

84.02

78.08
NGLs sold—MBbl/d(1)(2)
86.83

73.45

84.10

77.93
Condensate sold—MBbl/d3.75

4.11

4.75

5.54
Crude Oil—Gathered volumes—MBbl/d28.87

23.78

24.44

26.03
Transported volumes—TBtu445

441

1,383

1,352
Transported volumes—TBtu/d4.83

4.79

5.05

4.92
Interstate firm contracted capacity—Bcf/d5.62

6.89

6.35

7.00
Intrastate average deliveries—TBtu/d1.90

1.77

1.86

1.72
 _____________________
(1)Excludes condensate.
(2)NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.

 Three Months Ended 
 September 30,
Nine Months Ended 
 September 30,
 2017
2016
2017
2016
Anadarko






Gathered volumes—TBtu/d1.72

1.66

1.75

1.64
Natural gas processed volumes—TBtu/d1.57

1.50

1.56

1.45
NGLs produced—MBbl/d(1)
70.85

65.24

70.99

64.53
Arkoma






Gathered volumes—TBtu/d0.53

0.61

0.55

0.63
Natural gas processed volumes—TBtu/d0.09

0.10

0.09

0.10
NGLs produced—MBbl/d(1)
4.85

4.69

4.77

4.90
Ark-La-Tex






Gathered volumes—TBtu/d1.27

0.89

1.08

0.84
Natural gas processed volumes—TBtu/d0.24

0.18

0.24

0.23
NGLs produced—MBbl/d(1)
8.78

7.60

8.26

8.65
 _____________________
(1)Excludes condensate.


Gathering and Processing

Three Months Ended September 30, 20172021 compared to three months ended September 30, 20162020. Our gathering and processing segment reported operating income of $99$107 million for the three months ended September 30, 20172021 compared to operating income of $77$57 million for the three months ended September 30, 2016.2020. The difference of $22$50 million in operating income between periods was primarily due to a $25$49 million increase in gross margin and no impairments in the three months ended September 30, 2017 as compared to $8a $1 million of impairments in the three months ended September 30, 2016. This was partially offset by a $7 million increase in operation and maintenance and general and administrative expenses, a $3 million increasedecrease in depreciation and amortization and a $1 million increase in taxes other than income tax during the three months ended September 30, 2017.amortization.


Our gathering and processing segment revenues increased $87$376 million. The increase was primarily due to a $68 million increase in the following:
Product Sales:
•revenues from NGL sales resultingincreased $296 million primarily due to an increase in the average realized sales price from higher average market prices for NGL pricesproducts combined with higher recoveries of ethane and higher processed volumes, in the Anadarko Basin, a $14 million increase in
•revenues from natural gas gathering revenuessales increased $70 million due to higher feesaverage sales prices and gathered volumes in the Anadarko and Ark-La-Tex Basins and a $9 million increase in processing service revenues resulting from higher processed volumes primarily due to a percent-of-proceeds contract that was converted to a fee-based contract during the fourth quarter of 2016. These increases

were partially offset by a $9 million decrease in revenues from •changes in the fair value of natural gas, condensate and NGL derivatives aincreased $7 million.
These increases were partially offset by:
•higher realized losses on natural gas, condensate and NGL derivatives of $19 million.
Service Revenues:
•processing service revenues increased $21 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
•natural gas gathering revenues 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 crude oil, condensate and produced water gathering revenue, which decreased $5 million decrease in revenues from sales of natural gas and a $1 million decrease in revenuesprimarily due to a wind-downdecrease in gathered crude oil and condensate volumes from lower producer activity.

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Table of third-party measurement and communication services in 2017.Contents

Our gathering and processing segment gross margin increased $25$49 million. The increase was primarily due to a $14the following:
•revenues from NGL sales, less the cost of NGLs increased $42 million primarily due to an increase in gathering margin due to increased gathered volumes in the Anadarko and Ark-La-Tex Basins and increased billings under minimum volume commitments, an $11 million increase in processing margins resultingaverage realized sales price from higher average market prices for NGL pricesproducts combined with higher recoveries of ethane and higher processed volumes, in the Anadarko Basin
•processing service fees increased $21 million due to higher consideration received from percent-of-proceeds, percent-of-liquids and an $8 million increase in natural gas saleskeep-whole processing arrangements due to higher average natural gasmarket prices, and higher volumes in the Anadarko and Ark-La-Tex Basins. These increases were partially offset by a $9 million decrease in gross margin from lower processed volumes under fee-based arrangements,
•changes in the fair value of natural gas, condensate and NGL derivatives increased $7 million and
•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:
•higher realized losses on natural gas, condensate and a $1NGL derivatives of $19 million, decrease in margin
•crude oil, condensate and produced water gathering revenues decreased $5 million primarily due to a wind-downdecrease in gathered crude oil and condensate volumes from lower producer activity and
•revenues from natural gas sales, less the cost of third-party measurement and communication services in 2017.natural gas decreased approximately $3 million due to higher natural gas purchase costs.


Our gathering and processing segment operation and maintenance and general and administrative expenses increased $7 million.remained flat. The increase was primarily due toprimary activity resulted in a $3$4 million increase due to a reduction in capitalized overhead costs, a $1 million increasedecrease in payroll-related costs as a $1 million increase in employee expenses, a $1 million increase in materials and supplies expenseresult of lower headcount and a $1 million decrease due to insurance proceeds, partially offset by 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 allowance for doubtful accounts.pending merger with Energy Transfer.


Our gathering and processing segment depreciation and amortization increased $3decreased $1 million primarily due to additional assets placed in service.retirements of general plant assets.


Our gathering and processing segment recognized no impairments in the three months ended September 30, 2017 as compared to $8 million of impairments in the three months ended September 30, 2016 on our Service Star business line.

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

Nine months ended September 30, 20172021 compared to nine months ended September 30, 20162020. Our gathering and processing segment reported operating income of $241$247 million for the nine months ended September 30, 20172021 compared to operating income of $142$167 million for the nine months ended September 30, 2016.2020. The difference of $99$80 million in operating income between periods was primarily due to a $117$30 million increase in gross margin, and no impairments in the three months ended September 30, 2017 as compared to $8$28 million of property, plant and equipment and goodwill impairments recognized in the three months ended September 30, 2016. This was partially offset by2020 with no comparable item in 2021, and a $13$21 million increase in depreciation and amortization, a $10 million increasedecrease in operation and maintenance and general and administrative expenses and a $3 million increase in taxes other than income tax during the nine months ended September 30, 2017.expenses.


Our gathering and processing segment revenues increased $338$805 million. The increase was primarily due to a $187 million increase in the following:
Product Sales:
•revenues from NGL sales resultingincreased $672 million primarily due to an increase in the average realized sales price from higher average market prices for NGL pricesproducts combined with higher recoveries of ethane and higher processed volumes in the Anadarko Basin, a $79 million increase in
•revenues from sales of natural gas as a result of higher average natural gas prices and higher gathering volumes in the Anadarko and Ark-La-Tex Basins, a $26sales increased $170 million increase in natural gas gathering revenues due to higher feesaverage sales prices, partially offset by lower sales volumes.
These increases were partially offset by:
•higher realized losses on natural gas, condensate and gathered volumes in the Anadarko BasinNGL derivatives of $49 million and increased billings under minimum volume commitments in the Arkoma Basin, a $23 million increase in processing service revenues resulting from higher processed volumes primarily due to a percent-of-proceeds contract that was converted to a fee-based contract in the fourth quarter of 2016, a $22 million increase in revenues from
•changes in the fair value of natural gas, condensate and NGL derivatives decreased $18 million.
Service Revenues:
Processing service revenues increased $33 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 $2decrease in the recognition of certain annual minimum processing fees.
This increase was partially offset by:
•natural gas gathering revenues, which decreased $3 million due to lower average rates on certain contracts and volume curtailments and production freeze-offs related to Winter Storm Uri, partially offset by higher assessed producer imbalance penalties and
44
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•crude oil, condensate and produced water gathering revenue remained flat, due to an increase in revenues due to increased water transportation servicesgathered crude oil volumes in the Williston Basin. These increases were partiallyBasin, offset by a $3 million decrease in revenuesgathered crude oil and condensate volumes in the Anadarko Basin primarily due to a wind-down of third-party measurement and communication services in 2017.lower producer activity.


Our gathering and processing segment gross margin increased $117$30 million. The increase was primarily due to a $44the following:
•revenues from NGL sales, less the cost of NGLs increased $98 million primarily due to an increase in natural gasthe average realized sales price from higher average market prices for NGL products combined with higher recoveries of ethane and
•processing service fees increased $33 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.
These increases were partially offset by:
•higher realized losses on natural gas, pricescondensate and higher gathering volumes inNGL derivatives of $49 million,
•revenues from natural gas sales, less the Anadarko and Ark-La-Tex Basins, a $29cost of natural gas decreased approximately $31 million increase in processing margins resulting from higher average NGL prices and higher processed volumes in the Anadarko Basin, a $26 million increase in gathering margin due to increased gathered volumes in the Anadarko Basin and increased billings under minimum volume commitments in the Arkoma Basin, a $22 million increase in gross margin from higher natural gas purchase costs, inclusive of purchase costs related to Winter Storm Uri,
•changes in the fair value of natural gas, condensate and NGL derivatives and a $2decreased $18 million, increase
•natural gas gathering fees decreased $3 million due to increasedlower average rates on certain contracts and volume curtailments and production freeze-offs related to Winter Storm Uri, partially offset by higher assessed producer imbalance penalties and
•crude oil, condensate and produced water transportation servicesgathering revenue remained flat, due to an increase in gathered crude oil volumes in the Williston Basin. These increases were partiallyBasin, offset by a $6 million decrease in margin associated with our annual fuel rate determinationgathered crude oil and a $3 million decreasecondensate volumes in marginthe Anadarko Basin primarily due to a wind-down of third-party measurement and communication services in 2017.lower producer activity.


Our gathering and processing segment operation and maintenance and general and administrative expenses increased $10decreased $21 million. The increasedecrease was primarily due to a $20 million loss on retirement of an Ark-La-Tex gathering system in 2020, with minor activity in 2021, a $13 million decrease in payroll-related costs as a result of lower headcount, a $5 million decrease in field equipment rentals and a $2 million decrease due to insurance proceeds, partially offset by remediation costs associated with our Williston Basin operations. These decreases were partially offset by a $16 million increase in payroll-relatedprofessional services primarily due to transaction costs related to the pending merger with Energy Transfer and a $3$2 million increase due to a reduction inlower capitalized overhead costs, a $1 million increase in employee expenses and a $1 million increase in materials and supplies expense.costs.


Our gathering and processing segment depreciation and amortization increased $13decreased $1 million primarily due to additional assets placed in service.retirements of general plant assets.


Our gathering and processing segment recognized no impairments inDuring the nine months ended September 30, 2017 as compared to $82020, our gathering and processing segment recognized impairments of property, plant and equipment and goodwill of $28 million of impairmentswith no impairment recognized in the nine2021.

Transportation and Storage

Three months ended September 30, 2016 on our Service Star business line.

Our gathering and processing segment taxes other than income tax increased $3 million due to higher accrued ad valorem taxes due to additional assets placed in service.

Transportation and Storage

Three Months Ended September 30, 20172021 compared to three months ended September 30, 20162020. Our transportation and storage segment reported operating income of $38$46 million for the three months ended September 30, 20172021 compared to operating income of $62$43 million for the three months ended September 30, 2016.2020. The difference of $24$3 million in operating income between periods was primarily due to a $21 million decrease in gross margin, a $3 million increase in depreciation and amortization and a $1 million increase in taxes other than income, partially offset by a $1$4 million decrease in operation and maintenance and general and administrative expenses, for the three months ended September 30, 2017.and a $1 million decrease in taxes other than income tax, partially offset by a $2 million decrease in gross margin.


Our transportation and storage segment revenues decreased $8increased $74 million. The decreaseincrease was primarily due to an $11 million decrease in firm transportation services between Carthage, Texas, and Perryville, Louisiana, a $5 million decrease in the following:
Product Sales:
•revenues from natural gas sales increased $81 million primarily due to higher average sales prices,
•revenues from NGL sales increased $3 million due to higher average sales prices, partially offset by lower volumes and
•changes in the fair value of natural gas derivatives, and awhich increased $1 million decrease in revenues from transportation services for LDCs. million.
These decreasesincreases were partially offset by an increase of $3 million in revenues fromhigher realized losses on natural gas sales associated with higher sales volumesderivatives of $7 million.
45
Table of Contents
Service Revenues:
•volume-dependent transportation and higher average sales prices, a $3 million increase in revenues from off-system transportation, astorage revenue increased $2 million increase in revenues from NGL salesprimarily due to an increase in pricesinterstate transported volumes.
This increase was offset by firm transportation and volumes and a $2storage services, which decreased $6 million increaseprimarily due to higher realized gainsinterstate contract extensions at lower rates and reductions in contracted capacity on natural gas derivatives.certain intrastate firm transportation agreements.


Our transportation and storage segment gross margin decreased $21$2 million. The decrease was primarily due to an $11the following:
•higher realized losses on natural gas derivatives of $7 million decrease in and
•firm transportation and storage services between Carthage, Texasdecreased $6 million primarily due to interstate contract extensions at lower rates and Perryville, Louisiana, an $11 million decreasereductions in contracted capacity on certain intrastate firm transportation agreements.
These decreases were partially offset by:
•system management activities aincreased $5 million, decrease
•volume-dependent transportation and storage revenue increased $2 million primarily due to an increase in gross margininterstate transported volumes,
•a $2 million reduction in lower of cost or net realizable value adjustments related to natural gas storage inventories,
•revenues from NGL sales, less the cost of NGLs increased $1 million due to an increase in average NGL prices, partially offset by lower volumes and
•changes in the fair value of natural gas derivatives, and awhich increased $1 million decrease in margins from transportation services for LDCs. These decreases were partially offset by a $3 million increase in off-system transportation margins, a $2 million increase in realized gains on natural gas derivatives and a $1 million increase in NGL sales due to an increase in prices and volumes.million.


Our transportation and storage segment operation and maintenance and general and administrative expenses decreased $1$4 million. The decrease was primarily due todriven by a $2$3 million decrease in payroll-related costs as a result of lower headcount and a $3 million decrease due to the receipt of previously reserved amounts in allowance for doubtful accounts, partially offset by a $1 million increase due to a decrease in various other operatingcapitalized costs.

Our transportation and storage segment depreciation and amortization increased $3 million due to additional assets placed in service.


Our transportation and storage segment taxes other than income tax increaseddecreased $1 million primarily due to higher accrued ad valorem taxes due to additional assets placed in service.favorable tax assessments.


Nine months ended September 30, 20172021 compared to nine months ended September 30, 20162020. Our transportation and storage segment reported operating income of $158$235 million infor the nine months ended September 30, 20172021 compared to operating income of $157$159 million infor the nine months ended September 30, 2016.2020. The difference of $1$76 million in operating income between periods was primarily due to a $3$68 million increase in gross margin and a $5$8 million decrease in operation and maintenance and general and administrative expenses, partially offset by a $6 million increase in depreciation and amortization and a $1 million increase in taxes other than income for the nine months ended September 30, 2017.expenses.


Our transportation and storage segment revenues increased $78$392 million. The increase was primarily due to a $47 million increase in the following:
Product Sales:
•revenues from natural gas sales increased $414 million primarily due to higher average sales prices and sales volumes and
•revenues from NGL sales increased $6 million due to higher average sales prices, partially offset by lower volumes.
These increases were partially offset by:
•higher realized losses on natural gas derivatives of $8 million and
•changes in the fair value of natural gas derivatives, a $45which decreased $1 million.
Service Revenues:
•volume-dependent transportation and storage revenues increased $8 million increase in revenues from higher natural gas sales associated with higher sales volumes and higher average sales prices, a $7 million increase in revenues from NGL sales due to an increase in prices, a $6 million increase in revenues from off-system transportationinterstate transported volumes and a $2 million increase in revenues from firm transportation. These increases wereassessed shipper imbalance penalties, partially offset by a $15lower 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 decreaseof revenue upon the settlement of the MRT rate case with no comparable item in 2021
46
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This increase was partially offset by firm transportation and storage services between Carthage, Texas, and Perryville, Louisiana, a decrease of $8which decreased $27 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 realized gains on natural gas derivativesrates and a $2 million decrease in revenues fromterminations of certain intrastate firm transportation services for LDCs.agreements.



Our transportation and storage segment gross margin increased $3$68 million. The increase was primarily due to a $47the following:
•system management activities increased $85 million primarily due to higher average natural gas sales prices, less the cost of natural gas,
•volume-dependent transportation and storage revenues increased $8 million due to an increase in gross margininterstate 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 $27 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,
•higher realized losses on natural gas derivatives of $8 million and
•changes in the fair value of natural gas derivatives, a $6 million increase in off-system transportation margins, a $4 million increase in NGL sales due to an increase in prices and a $2 million increase in firm transportation. These increases were partially offset by a $32 million decrease in system management activities, a decrease of $15 million in firm transportation services between Carthage, Texas, and Perryville, Louisiana, a decrease of $8 million due to realized gains on natural gas derivatives as compared to realized losses in 2016 and a $2 million decrease in margins from transportation services for LDCs.which decreased $1 million.


Our transportation and storage segment operation and maintenance and general and administrative expenses decreased $5$8 million. The decrease was primarily due todriven by a $4$9 million decrease in materials and supplies and contract servicespayroll-related costs as a result of lower headcount and a $2$3 million decrease in loss on sale of assets.operation and maintenance outside services. These decreases were partially offset by a $3 million increase in loss contingencies and a $1 million increase due to a decrease in payroll-relatedcapitalized costs.


Our
Condensed Consolidated Interim Information
 Three Months Ended September 30,Nine Months Ended
September 30,
 2021202020212020
 (In millions)
Operating Income$152 $100 $482 $326 
Other Income (Expense):
Interest expense(41)(43)(125)(136)
Equity in earnings (losses) of equity method affiliate, net (1)
4 (222)5 (211)
Other, net1 2 7 7 
Total Other Expense(36)(263)(113)(340)
Income (Loss) Before Income Taxes116 (163)369 (14)
Income tax benefit— — — — 
Net Income (Loss)$116 $(163)$369 $(14)
Less: Net income (loss) attributable to noncontrolling interest— 1 2 (6)
Net Income (Loss) Attributable to Limited Partners$116 $(164)$367 $(8)
Less: Series A Preferred Unit distributions9 9 26 27 
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 depreciationfor the three and amortization increased $6 million due to additional assets placed in service.

Our transportationnine months ended September 30, 2021 and storage segment taxes other than income tax increased $1 million due to higher accrued ad valorem taxes due to additional assets placed in service.


Condensed Consolidated Interim Information
2020.
47
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 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (In millions)
Operating Income$137
 $139
 $399
 $299
Other Income (Expense):       
Interest expense(31) (26) (89) (74)
Equity in earnings of equity method affiliate7
 8
 21
 22
Total Other Expense(24) (18) (68) (52)
Income Before Income Taxes113
 121
 331
 247
Income tax expense—
 2
 2
 3
Net Income$113
 $119
 $329
 $244
Less: Net income attributable to noncontrolling interest—
 —
 1
 —
Net Income Attributable to Limited Partners$113
 $119
 $328
 $244
Less: Series A Preferred Unit distributions9
 9
 27
 13
Net Income Attributable to Common and Subordinated Units$104
 $110
 $301
 $231


Three Months Ended September 30, 20172021 compared to Three Months Ended September 30, 20162020


Net Income attributable(Loss) Attributable to limited partners.Limited Partners. We reported net income attributable to limited partners of $113$116 million in the three months ended September 30, 20172021 compared to net incomeloss attributable to limited partners of $119$164 million in the three months ended September 30, 2016. The decrease in net income attributable to limited partners of $6 million was primarily attributable to an increase in interest expense of $5 million as well as a decrease in operating income of $2 million in the three months ended September 30, 2017.

Interest Expense. Interest expense increased $5 million primarily due to higher interest rates on the Partnership’s outstanding debt.

Nine Months Ended September 30, 2017 compared to Nine Months Ended September 30, 2016

Net Income attributable to limited partners. We reported net income attributable to limited partners of $328 million in the nine months ended September 30, 2017 compared to net income attributable to limited partners of $244 million in the nine months ended September 30, 2016.2020. The increase in net income attributable to limited partners of $84$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 $100$52 million, partially offset by an increasea decrease in interest expense of $15$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, 2017.2021 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.



Interest Expense. Interest expenseEquity in Earnings (Losses) of Equity Method Affiliate, net. Equity in earnings (losses) of equity method affiliate, net increased $15$216 million primarily due to highera $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 outstanding debt.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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Table of Contents
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.Condensed Consolidated Financial Statements. Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio are part of the performance measures that we use to manage the Partnership.


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

Three Months Ended September 30,Nine Months Ended
September 30,
2021202020212020
(In millions)
Reconciliation of Gross margin to Total Revenues:
Consolidated
Product sales$623 $280 $1,710 $764 
Service revenues333 316 1,003 995 
Total Revenues956 596 2,713 1,759 
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)565 250 1,510 653 
Gross margin$391 $346 $1,203 $1,106 
Reportable Segments
Gathering and Processing
Product sales$625 $271 $1,514 $739 
Service revenues214 192 622 592 
Total Revenues839 463 2,136 1,331 
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)571 244 1,406 631 
Gross margin$268 $219 $730 $700 
Transportation and Storage
Product sales$157 $79 $624 $213 
Service revenues122 126 390 409 
Total Revenues279 205 1,014 622 
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)154 78 539 215 
Gross margin$125 $127 $475 $407 

49

Three Months Ended 
 September 30,
Nine Months Ended 
 September 30,

2017
2016
2017
2016

(In millions)
Reconciliation of Gross margin to Total Revenues:






Consolidated






Product sales$396

$326

$1,136

$837
Service revenue309

294

861

821
Total Revenues705

620

1,997

1,658
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)349

268

936

717
Gross margin$356

$352

$1,061

$941








Reportable Segments






Gathering and Processing






Product sales$357

$295

$1,044

$759
Service revenue185

160

469

416
Total Revenues542

455

1,513

1,175
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)308

246

863

642
Gross margin$234

$209

$650

$533








Transportation and Storage






Product sales$152

$150

$439

$348
Service revenue125

135

395

408
Total Revenues277

285

834

756
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)154

141

421

346
Gross margin$123

$144

$413

$410
Table of Contents


The following table shows the components of our gross marginmargin.
 
Fee-Based (1)
 
Nine Months Ended September 30, 2021DemandVolume-
Dependent
Commodity-
Based (1)
Total
Gathering and Processing Segment12 %66 %22 %100 %
Transportation and Storage Segment72 %10 %18 %100 %
Partnership Weighted Average36 %43 %21 %100 %
____________________
(1)For purposes of this table, the Partnership includes the value of all natural gas and NGL commodities received as payment as commodity-based.
Three Months Ended September 30,Nine Months Ended
September 30,
2021202020212020
(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 (loss) attributable to limited partners$116 $(164)$367 $(8)
Depreciation and amortization expense104 105 313 314 
Interest expense, net of interest income40 43 124 135 
Distributions received from equity method affiliate in excess of equity earnings(3)1 — 9 
Impairment of equity method affiliate investment— 225 — 225 
Non-cash equity-based compensation4 3 12 10 
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)
Noncontrolling Interest Share of Adjusted EBITDA— — — (9)
Adjusted EBITDA$269 $229 $848 $739 
Series A Preferred Unit distributions (3)
(9)(9)(26)(27)
Distributions for phantom and performance units (4)
(1)— (1)(1)
Adjusted interest expense (5)
(39)(42)(122)(134)
Maintenance capital expenditures(27)(31)(61)(69)
Current income taxes— — — 1 
DCF$193 $147 $638 $509 
Distributions related to common unitholders (6)
$72 $72 $216 $216 
Distribution coverage ratio (7)
2.68 2.04 2.95 2.36 
____________________
(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 ninethree months ended September 30, 2017:2021 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.
 Fee-Based  
 
Demand/
Commitment/
Guaranteed
Return
 
Volume
Dependent
 
Commodity-
Based
 Total
Nine Months Ended September 30, 2017       
Gathering and Processing Segment29% 45% 26% 100%
Transportation and Storage Segment87% 7% 6% 100%
Partnership Weighted Average52% 29% 19% 100%
(5)See below for a reconciliation of Adjusted interest expense to Interest expense.


Three Months Ended 
 September 30,
Nine Months Ended 
 September 30,

2017
2016
2017
2016

(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$113

$119

$328

$244
Depreciation and amortization expense90

84

267

248
Interest expense, net of interest income31

26

89

74
Income tax expense—

2

2

3
Distributions received from equity method affiliate in excess of equity earnings4

5

9

18
Non-cash equity-based compensation4

4

12

9
Change in fair value of derivatives6

(8)
(29)
40
Other non-cash losses(1)
2

4

8

11
Impairments—

8

—

8
Adjusted EBITDA$250

$244

$686

$655
Series A Preferred Unit distributions(2)
(9)
(9)
(27)
(22)
Distributions for phantom and performance units(1)
—

(2)
—
Adjusted interest expense(3)
(31)
(27)
(90)
(76)
Maintenance capital expenditures(22)
(21)
(53)
(51)
Current income taxes—

2

—

1
DCF$187

$189

$514

$507








Distributions related to common and subordinated unitholders(4)
$138

$134

$413

$402








Distribution coverage ratio1.36

1.41

1.25

1.26
____________________
(1)
Other non-cash losses includes loss on sale of assets and write-downs of materials and supplies.
(2)
This amount represents the quarterly cash distributions on the Series A Preferred Units declared for the three and nine months ended September 30, 2017 and 2016. The nine months ended September 30, 2016 amount includes the prorated quarterly cash distribution on the Series A Preferred Units declared on April 26, 2016. 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.
(3)
See below for a reconciliation of Adjusted interest expense to Interest expense.
(4)
(6)Represents cash distributions declared for common units outstanding as of each respective period. Amounts for 2021 reflect estimated cash distributions for common and subordinated units outstanding as of each respective period. Amounts for 2017 reflect estimated cash distributions for common and subordinated units outstanding for the quarter ended September 30, 2017.



Three Months Ended 
 September 30,
Nine Months Ended 
 September 30,

2017
2016
2017
2016

(In millions)
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:






Net cash provided by operating activities$174

$209

$556

$498
Interest expense, net of interest income31

26

89

74
Net income attributable to noncontrolling interest—

—

(1)
—
Current income taxes—

(2)
—

(1)
Other non-cash items(1)
—

3

2

4
Changes in operating working capital which (provided) used cash:






Accounts receivable100

47

72

25
Accounts payable(30)
4

16

88
Other, including changes in noncurrent assets and liabilities(35)
(40)
(28)
(91)
Return of investment in equity method affiliate4

5

9

18
Change in fair value of derivatives6

(8)
(29)
40
Adjusted EBITDA$250

$244

$686

$655
____________________
(1)
Other non-cash items includes amortization of debt expense, discount and premium on long-term debt and write-downs of materials and supplies.


Three Months Ended 
 September 30,
Nine Months Ended 
 September 30,

2017
2016
2017
2016

(In millions)
Reconciliation of Adjusted interest expense to Interest expense:






Interest Expense$31

$26

$89

$74
Amortization of premium on long-term debt1

1

4

4
Capitalized interest on expansion capital—

—

—

1
Amortization of debt expense and discount(1)
—

(3)
(3)
Adjusted interest expense$31

$27

$90

$76


Liquidity and Capital Resources
Working Capital
Working capital is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from, customers, and the level and timing of spending for maintenance and expansion activity. As of September 30, 2017, we had a working capital deficit of $385 million. The deficit is primarily due to the classification of the 2015 Term Loan Agreement as Current portion of long-term debt as of September 30, 2017. We utilize our revolving credit facility to manage the timing of cash flows and fund short-term working capital deficits.

Cash Flows
The following tables reflect cash flows for the applicable periods:
 Nine Months Ended 
 September 30,
 2017 2016
 (In millions)
Net cash provided by operating activities$556
 $498
Net cash used in investing activities$(240) $(270)
Net cash used in financing activities$(317) $(209)
Operating Activities
The increase of $58 million, or 12%, in net cash provided by operating activities for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016 was primarily due to an increase in net income of $85 million.

Investing Activities
The decrease of $30 million, or 11%, in net cash used in investing activities for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016 was primarily due to lower capital expenditures of $39 million partially offset by a decrease in return of investment in equity method affiliate of $9 million.

Financing Activities

Net cash used in financing activities increased $108 million for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016. Our primary financing activities consist of the following:

 Nine Months Ended 
 September 30,
 2017 2016
 (In millions)
Proceeds from 2027 Notes, net of issuance costs$691
 $—
Net (repayments) proceeds from Revolving Credit Facility(563) 445
Repayments from commercial paper program—
 (236)
Repayment of notes payable—affiliated companies—
 (363)
Proceeds from issuance of Series A Preferred Units, net of issuance costs—
 362
Distributions(443) (417)
Cash taxes paid for employee equity-based compensation(2) —

Please see Note 7, “Debt” in the Notes to the Unaudited Condensed Consolidated Financial Statements in Part 1, Item 1. for a description of the Partnership’s debt agreements.

Sources of Liquidity

As of September 30, 2017, our sources of liquidity included:
cash on hand;
cash generated from operations;
borrowings under our Revolving Credit Facility; and
capital raised through debt and equity markets.


Distribution Reinvestment Plan

In June 2016, the Partnership implemented a Distribution Reinvestment Plan (DRIP), which, beginning with the quarterly distribution for the quarter ended September 30, 2016, offers owners2021.
(7)Distribution coverage ratio is computed by dividing DCF by Distributions related to common unitholders.
50
Three Months Ended September 30,Nine Months Ended
September 30,
2021202020212020
(In millions)
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities$265 $232 $678 $543 
Interest expense, net of interest income40 43 124 135 
Noncontrolling interest share of cash provided by operating activities— (1)(3)(3)
Current income taxes— — — 1 
Equity AFUDC and other non-cash items (1)
— (2)(1)— 
Proceeds from insurance— 1 — 1 
Changes in operating working capital which (provided) used cash:
Accounts receivable55 3 130 (27)
Accounts payable(53)(24)(67)46 
Other, including changes in noncurrent assets and liabilities(42)(39)(49)17 
Return of investment in equity method affiliate(3)1 — 9 
Change in fair value of derivatives (2)
7 15 36 17 
Adjusted EBITDA$269 $229 $848 $739 
____________________
(1)Other non-cash items primarily includes write-downs of the cash distributions paid to them on their common or subordinated units. The Partnership will have the sole discretion to determine whether common units purchased under the DRIP will come from our newly issued common units or from common units purchased on the open market. The purchase price for newly issued common units will be the averageassets.
(2)Change in fair value of the high and low trading prices of the common units on the New York Stock Exchange-Composite Transactions for the five trading days immediately preceding the investment date. The purchase price for common units purchased on the open market will be the weighted average price of all common units purchased for the DRIP for the respective investment date. We can set a discount ranging from 0% to 5% for common units purchased pursuant to the DRIP. The discount is currently set at 0%. Participationderivatives includes changes in the DRIP is voluntary, and once enrolled, our unitholders may terminate participation at any time.fair value of derivatives that are not designated as hedging instruments.


Capital Requirements
Three Months Ended September 30,Nine Months Ended
September 30,
2021202020212020
(In millions)
Reconciliation of Adjusted interest expense to Interest expense:
Interest expense$41 $43 $125 $136 
Interest income(1)— (1)(1)
Amortization of premium on long-term debt— — — 1 
Capitalized interest on expansion capital— 1 2 2 
Amortization of debt expense and discount(1)(2)(4)(4)
Adjusted interest expense$39 $42 $122 $134 
The midstream business is capital intensive and can require significant investment to maintain and upgrade existing operations, connect new wells to the system, organically grow into new areas and comply with environmental and safety regulations. Going forward, our capital requirements will consist of the following:
maintenance capital expenditures, which are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long-term, our operating capacity or operating income; and
expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.
Our future expansion capital expenditures may vary significantly from period to period based on commodity prices and the investment opportunities available to us. We expect to fund future capital expenditures from cash flow generated from our operations, borrowings under our Revolving Credit Facility, new debt offerings or the issuance of additional partnership units. Issuances of equity or debt in the capital markets may not, however, be available to us on acceptable terms.
Distributions
On October 31, 2017, the board of directors of Enable GP declared a quarterly cash distribution of $0.318 per common unit on all of the Partnership’s outstanding common units for the period ended September 30, 2017. The distributions will be paid November 21, 2017 to unitholders of record as of the close of business on November 14, 2017. Additionally, the board of directors of Enable GP declared a quarterly cash distribution of $0.625 on the Partnership’s outstanding Series A Preferred Units. The distributions will be paid November 14, 2017 to unitholders of record as of the close of business on October 31, 2017.

Expiration of Subordination Period

The financial tests required for conversion of all subordinated units were met and the 207,855,430 outstanding subordinated units converted into common units on a one-for-one basis on August 30, 2017. The conversion of the subordinated units did not change the aggregate amount of outstanding units, and the conversion of the subordinated units did not impact the amount of cash available for distribution by the Partnership.

Off-Balance Sheet Arrangements
 
We do not have any off-balance sheet arrangements.

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



Critical Accounting Policies and Estimates
 
The Partnership’s critical accounting policies and estimates are described in Critical Accounting Policies and Estimates within Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 1 of the Notes to the Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” in our Annual Report on Form 10-K for the year ended December 31, 2016.Report. The accounting policies and estimates used in preparing our interim Condensed Consolidated Financial Statements for the three months ended September 30, 20172021 are the same as those described in our Annual Report on Form 10-K for the year ended December 31, 2016.Report.





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Table of Contents
Item 3. Quantitative and Qualitative Disclosures About Market Risk


We are exposed to various market risks, including volatility in commodity prices and interest rates.
 
Commodity Price Risk
 
While we generate a substantial portion of our gross margin pursuant to 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.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 8.10 of the Notes to the Condensed Consolidated Financial Statements.
 
Based on our forecasted volumes, prices and contractual arrangements, we estimate approximately 16%22% of our total gross margin for the twelve months endingended December 31, 20172021, is directly exposed to changes in commodity prices, excluding the impact of hedges and contractual floors related to commodity prices in certain agreements.


CommodityOur 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 sixthree 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 $3$4 million for natural gas and ethane and $3$5 million for NGLs excluding ethane(other than ethane) and condensate, excluding the impact of hedges, for the remaining three months ending December 31, 2017.2021.


Interest Rate Risk
 
Our current interest rate risk exposure is related primarily to our debt portfolio.portfolio and distributions on the Series A Preferred Units. Our debt portfolio is substantially comprised ofincludes senior notes with a fixed rate debt,of interest, which mitigates the impact of fluctuations in interest rates. Future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher interest costs. Borrowings under our Revolving Credit Facility, 20152019 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 $523$850 million outstanding borrowings under the 2015commercial paper and 2019 Term Loan Agreement and Revolving Credit Facility as of September 30, 2017,2021, 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 $5$9 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 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 Securities Exchange Act of 1934, as amended (the “Exchange Act”))Act) as of September 30, 2017.2021. Based on such evaluation, our management has concluded that, as of September 30, 2017,2021, 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.

52
Table of Contents

In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of 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 ControlControls Over Financial Reporting

During the three months ended September 30, 2017, the Partnership completed the implementation of natural gas and natural gas liquid marketing and risk management systems. The systems were implemented by the Partnership to improve standardization and not in response to any deficiency in internal control over financial reporting. Management believes the implementation of the systems and related changes to internal controls will enhance the Partnership's internal controls over financial reporting. Management believes the necessary steps have been taken to monitor and maintain appropriate internal control over financial reporting during this period of change and will continue to evaluate the operating effectiveness of related key controls during subsequent periods.


There were no other changes in our internal controls over financial reporting during the quarter ended September 30, 2017,2021, 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 12 - 14—Commitments and Contingencies to the Partnership’s condensed consolidated financial statementsCondensed Consolidated Financial Statements included in Item 1 of Part I of this Quarterly Report on Form 10-Q and is incorporated herein by reference.




Item 1A. Risk Factors


We are subject to various risks and uncertainties in the course of our business. Risk factors relating to the Partnership are set forth under “Risk Factors” in our Annual Report. No other material changes to such risk factors have occurred during the three and nine months ended September 30, 2017.2021.




Item 6. Exhibits

The following exhibits are filed herewith:


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






53
Table of Contents
Exhibit NumberDescriptionReport or Registration StatementSEC File or Registration NumberExhibit Reference
Registrant’s registration statement on Form S-1, filed on November 26, 2013File No. 333-192545Exhibit 2.1
Registrant’s Form 8-K filed
February 17, 2021		File No. 001-36413Exhibit 2.1
Registrant’s registration statement on Form S-1, filed on November 26, 2013File No. 333-192545Exhibit 3.1
Registrant’s Form 8-K filed June 22, 2016November 15, 2017File No. 001-36413Exhibit 3.1
Registrant’s Form 8-K filed April 22, 2014File No. 001-36413Exhibit 3.1
Registrant’s Form 8-K filed May 29, 2014File No. 001-36413Exhibit 4.1
Registrant’s Form 8-K filed May 29, 2014File No. 001-36413Exhibit 4.2
Registrant’s Form 8-K filed May 29, 2014File No. 001-36413Exhibit 4.3
Registrant’s Form 8-K filed February 19, 2016File No. 001-36413Exhibit 4.1
Registrant’s Form 8-K filed March 9, 2017File No. 001-36413Exhibit 4.2
Registrant’s Form 8-K filed May 10, 2018File No. 001-36413Exhibit 4.2
Registrant’s Form 8-K filed September 13, 2019File No. 001-36413Exhibit 4.2
Registrant’s Form 8-K filed
February 17, 2021		File No. 001-36413Exhibit 10.1
Registrant’s Form 8-K filed
February 17, 2021		File No. 001-36413Exhibit 10.2
+101.INSXBRL Instance Document.
+101.SCHXBRL Taxonomy Schema Document.
+101.PREXBRL Taxonomy Presentation Linkbase Document.
+101.LABXBRL Taxonomy Label Linkbase Document.
+101.CALXBRL Taxonomy Calculation Linkbase Document.
+101.DEFXBRL Definition Linkbase Document.

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Table of Contents

SIGNATURE
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
ENABLE MIDSTREAM PARTNERS, LP
(Registrant)
By: ENABLE GP, LLC
Its general partner
Date:November 1, 20172021By:
/s/ Tom Levescy
Tom Levescy
Senior Vice President, Chief Accounting Officer and Controller
(Principal Accounting Officer)
 


 
 

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